ML15219A599
ML15219A599 | |
Person / Time | |
---|---|
Site: | Diablo Canyon ![]() |
Issue date: | 08/07/2015 |
From: | Thomas Hipschman NRC/RGN-IV/DRP/RPB-A |
To: | Halpin E Pacific Gas & Electric Co |
RYAN ALEXANDER | |
References | |
EA-15-040 IR 2015002 | |
Download: ML15219A599 (52) | |
See also: IR 05000275/2015002
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION IV
1600 E. LAMAR BLVD.
ARLINGTON, TX 76011-4511
August 7, 2015
Mr. Edward D. Halpin
Senior Vice President
And Chief Nuclear Officer
Pacific Gas and Electric Company
Diablo Canyon Power Plant
P.O. Box 56, Mail Code 104/6
Avila Beach, CA 93424
SUBJECT:
DIABLO CANYON POWER PLANT - NRC INTEGRATED INSPECTION
REPORT 05000275/2015002 and 05000323/2015002
Dear Mr. Halpin:
On June 30, 2015, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at
your Diablo Canyon Power Plant Units 1 and 2. On July 7 and 28, 2015, the NRC inspectors
discussed the results of this inspection with Mr. James Welsh and other members of your staff.
Inspectors documented the results of this inspection in the enclosed inspection report.
NRC inspectors documented six findings of very low safety significance (Green) in this report.
Five of these findings involved a violation of NRC requirements, and one was determined to be
Severity Level IV under the traditional enforcement process.
Further, inspectors documented two licensee-identified violations which were determined to be
Severity Level IV in this report. The NRC is treating these violations as non-cited violations
(NCVs) consistent with Section 2.3.2.a of the NRC Enforcement Policy.
One of the licensee identified violations referenced above resulted in an NRC investigation. The
enclosed report documents the investigation completed on March 10, 2015, by the Nuclear
Regulatory Commission's Office of Investigations. The purpose of this investigation was to
determine whether on three separate occasions in 2014, a former licensee employee willfully
failed to perform transient combustible permit inspections and falsified inspections documents
regarding the completion of those inspections. Based on the evidence gathered during the
investigation, the NRC concluded that on three separate occasions in 2014, a former licensee
employee deliberately failed to perform the subject transient combustible permit inspections and
falsified inspection documents regarding the completion of those inspections at the Diablo
Canyon Power Plant. This was contrary to the fire protection plan as required by License
Conditions 2.C.(5) and 2.C.(4) of licenses DPR-80 and DPR-82, respectively, and resulted in a
violation. The NRC concluded that information regarding: (1) the reason for the violation, (2) the
corrective actions that have been taken and results achieved, and (3) the date when full
compliance was achieved is adequately addressed on the docket in the enclosed inspection
E. Halpin
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report. Therefore, you are not required to respond to this letter unless the description herein
does not accurately reflect your corrective actions or your position.
If you contest the violations or significance of these NCVs, you should provide a response within
30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear
Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with
copies to the Regional Administrator, Region IV; the Director, Office of Enforcement,
U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC resident
inspector at the Diablo Canyon Power Plant.
If you disagree with a cross-cutting aspect assignment in this report, you should provide a
response within 30 days of the date of this inspection report, with the basis for your
disagreement, to the Regional Administrator, Region IV; and the NRC resident inspector at the
Diablo Canyon Power Plant.
In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public
Inspections, Exemptions, Requests for Withholding, a copy of this letter, its enclosure, and your
response (if any) will be available electronically for public inspection in the NRCs Public
Document Room or from the Publicly Available Records (PARS) component of the NRC's
Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible
from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic
Reading Room).
Sincerely,
/RA R. Alexander for/
Thomas Hipschman, Acting Branch Chief
Projects Branch A
Division of Reactor Projects
Docket Nos. 05000275, 05000323
Enclosure:
Inspection Report 05000275/2015002 and
w/ Attachment: Supplemental Information
cc w/ enclosure: Electronic Distribution
SUNSI Review
By: RDA
Yes No
Non-Sensitive
Sensitive
Publicly Available
Non-Publicly Available
OFFICE
SRI:DRP/A
RI:DRP/A
C:DRS/EB1
C:DRS/EB2
C:DRS/OB
C:DRS/PSB1
C:DRS/PSB2
NAME
THipschman
JReynoso
TFarnholtz
GPick
VGaddy
MHaire
HGepford
SIGNATURE
/RA/ via E
/RA/ via T
/RA/
/RA/
/RA/
/RA/
/RA/
DATE
08/06/15
08/07/15
07/30/15
08/03/15
08/03/15
07/31/15
08/03/15
OFFICE
TL:DRS/TSS
SPE:DRP/A
ORA/ACES
SRA:TSB
AC:DRP/A
NAME
ERuesch
RAlexander
MHay
DLoveless
THipschman
SIGNATURE
/RA/
HFreeman for
/RA/
/RA/
JKramer for
/RA/
/RA/
RAlexander
for
DATE
08/03/15
08/05/15
08/06/15
08/03/15
08/07/15
Letter to Edward D. Halpin from Thomas Hipschman dated August 7, 2015
SUBJECT:
DIABLO CANYON POWER PLANT - NRC INTEGRATED INSPECTION
REPORT 05000275/2015002 and 05000323/2015002
DISTRIBUTION:
Regional Administrator (Marc.Dapas@nrc.gov)
Deputy Regional Administrator (Kriss.Kennedy@nrc.gov)
DRP Director (Troy.Pruett@nrc.gov)
DRP Deputy Director (Ryan.Lantz@nrc.gov)
DRS Director (Anton.Vegel@nrc.gov)
DRS Deputy Director (Jeff.Clark@nrc.gov)
Senior Resident Inspector (Thomas.Hipschman@nrc.gov)
Resident Inspector (John.Reynoso@nrc.gov)
Administrative Assistant (Madeleine.Arel-Davis@nrc.gov)
Acting Branch Chief, DRP/A (Thomas.Hipschman@nrc.gov)
Senior Project Engineer, DRP/A (Ryan.Alexander@nrc.gov)
Project Engineer, DRP/A (Thomas.Sullivan@nrc.gov)
Public Affairs Officer (Victor.Dricks@nrc.gov)
Public Affairs Officer (Lara.Uselding@nrc.gov)
Project Manager (Siva.Lingam@nrc.gov)
Acting Team Leader, DRS/TSS (Eric.Ruesch@nrc.gov)
RITS Coordinator (Marisa.Herrera@nrc.gov)
ACES (R4Enforcement.Resource@nrc.gov)
Regional Counsel (Karla.Fuller@nrc.gov)
Technical Support Assistant (Loretta.Williams@nrc.gov)
RIV Congressional Affairs Officer (Angel.Moreno@nrc.gov)
RIV/ETA: OEDO (Cindy.Rosales-Cooper@nrc.gov)
ROPreports
- 1 -
Enclosure
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket:
05000275; 05000323
License:
Report:
05000275/2015002; 05000323/2015002
Licensee:
Pacific Gas and Electric Company
Facility:
Diablo Canyon Power Plant, Units 1 and 2
Location:
7 1/2 miles NW of Avila Beach
Avila Beach, CA
Dates:
April 1 through June 30, 2015
Inspectors: T. Hipschman, Senior Resident Inspector
J. Reynoso, Resident Inspector
R. Alexander, Senior Project Engineer
T. Buchanan, Operations Engineer
M. Hayes, Operations Engineer
M. Kennard, Operations Engineer
Approved
By:
Thomas Hipschman, Acting Chief
Projects Branch A
Division of Reactor Projects
- 2 -
SUMMARY
IR 05000275/2015002, 05000323/2015002; 04/01/2015 - 06/30/2015; Diablo Canyon Power
Plant; Fire Protection, Licensed Operator Requalification, Problem Identification and Resolution,
Follow-up of Events and Notices of Enforcement Discretion
The inspection activities described in this report were performed between April 1 and
June 30, 2015, by the resident inspectors at Diablo Canyon Power Plant and inspectors from
the NRCs Region IV office. Six findings of very low safety significance (Green) are documented
in this report. Five of these findings involved violations of NRC requirements, and one was
determined to be Severity Level IV under the traditional enforcement process. The significance
of inspection findings is indicated by their color (Green, White, Yellow, or Red), which is
determined using Inspection Manual Chapter 0609, Significance Determination Process. Their
cross-cutting aspects are determined using Inspection Manual Chapter 0310, Aspects within
the Cross-Cutting Areas. Violations of NRC requirements are dispositioned in accordance with
the NRC Enforcement Policy. The NRCs program for overseeing the safe operation of
commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process.
Cornerstone: Initiating Events
Green. The inspectors identified a Green, non-cited violation of 10 CFR 50.65(b)(2) for the
licensees failure to appropriately scope the 230 kV switchyard in the Maintenance Rule
monitoring program. Specifically, from the inception of the facilities monitoring program
through May 18, 2015, the licensee failed to properly scope or evaluate the 230 kV
switchyard to include the entire switchyard up through the first inter-tie circuit breakers
CB262 and CB282 into the Maintenance Rule program. Electrical faults within the 230 kV
switchyard can cause loss of offsite power which is relied upon to mitigate accidents and
cause an actuation of a safety-related systems, such as, emergency diesel generators, and
should have been included into its Maintenance Rule program. This issue was entered into
the licensees corrective action program as Notifications 50702970 and 50703118.
The inspectors determined that the licensees failure to scope the 230 kV offsite power
source including the switchyard up through the first breakers from the transmission system
into the Maintenance Rule program was contrary to the requirements of 10 CFR 50.65 and
therefore a performance deficiency. The performance deficiency was determined to be
more than minor because it is associated with the initiating events attribute of protections
against external factors and adversely affected the cornerstone objective, in that, a 230 kV
switchyard failure can upset plant stability and challenge critical safety functions during
shutdown as well as power operations. Failure to monitor the performance or condition of
230 kV offsite power source (including the switchyard up through the first breakers from the
transmission system) in a manner sufficient to provide reasonable assurance the offsite
power was capable of fulfilling the intended functions affected the reliability of the plant
equipment to perform their safety function. The inspectors determined if the 230 kV
switchyard was properly scoped into the Maintenance Rule program the loss of offsite power
due to the flash over event may have been prevented. However the direct cause of the
event has been identified as untimely corrective actions associated with an ineffective
corrective action program. As such, improper Maintenance Rule scoping was not the direct
cause. Therefore, the inspectors determined the finding could be evaluated using the
significant determination process in accordance using IMC 0609, Appendix A, Significance
Determination Process (SDP) for Findings At-Power, Exhibit 1, Initiating Events Screening
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Questions. The inspectors determined that the finding was of very low safety significance
(Green) because the finding was determined not to be the cause of the actual 230 kV failure
such that all of the screening questions in Exhibit 1 could be answered no. The inspectors
determined that since the scoping of the switchyard systems had occurred more than 3
years ago, and the opportunity to reevaluate system scoping had not recently occurred, the
finding did not represent current licensee performance and therefore a cross-cutting aspect
was not assigned. (Section 4OA3.4.b.(1))
Green. The inspectors reviewed a self-revealing, Green finding for the licensees failure to
adequately implement procedure OM7.ID1, Problem Identification and Resolution, to
prevent a high voltage insulator flashover event in the 230 kV switchyard that occurred on
October 31, 2014. Specifically, corrective actions from three previous root cause
evaluations were not effective to prevent a loss of the 230 kV start-up power and
subsequent auto start of all of the safety standby emergency diesel generators (EDGs). This
issue was entered into the licensees corrective action program as Notification 50699230.
The licensees failure to adequately implement procedure OM7.ID1, Problem Identification
and Resolution was a performance deficiency. The performance deficiency was more than
minor because it was associated with the human performance attribute of the Initiating
Events cornerstone and affected the cornerstone objective to limit the likelihood of those
events that upset plant stability and challenge critical safety functions. Specifically, this
failure resulted in another high-voltage insulator flashover, which resulted in loss of 230 kV
offsite startup power and activation of all safety-related EDGs, on October 31, 2014. In
accordance with IMC 0609.04, Initial Characterization of Findings, the inspectors
determined that the impact of the finding on Unit 1 should be evaluated using Exhibit 1 of
IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at
Power, and further determined that this finding required a detailed risk evaluation by the
regional senior risk analyst because the finding involved a partial loss of offsite power, a
support system that contributes to the likelihood of an initiating event and affected mitigation
equipment.
The risk analyst determined that, with the 230 kV system de-energized, any plant transient
would result in a plant-centered loss of offsite power. Therefore, the risk analyst calculated
the incremental conditional core damage probability for an exposure period of 9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> to be
2.09 x 10-7, which is lower than the 1 x 10-6 threshold in the significance determination
process; this finding is of very low safety significance (Green) for Unit 1. In accordance with
IMC 0609.04, Initial Characterization of Findings, the inspectors determined that the
impact of the finding on Unit 2 should be evaluated using IMC 0609, Appendix G, Shutdown
Operations Significance Determination Process, because the finding pertained to
operations, an event, or a degraded condition while the plant was shut down. Unit 2 was
shutdown in a refueling outage when the event occurred on October 31, 2014. Because of
the shutdown configuration of Unit 2, the loss of 230 kV support system did not impact the
ability to continue to provide decay heat removal for the unit. Therefore, the analyst
determined qualitatively that this finding is also of very low safety significance (Green) for
Unit 2. This finding has a cross-cutting aspect of work management, in the area of human
performance, for failing to implement a process of planning, controlling, and executing work
activities such that nuclear safety is an overriding priority. Specifically the licensee failed to
effectively plan and coordinate preventative maintenance strategies associated with root
causes from previous high-voltage insulators flashover or failures since 2008 to prevent the
loss of offsite 230 kV and the transient on October 31, 2014 [H.5]. (Section 4OA3.4.b.(2))
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Cornerstone: Mitigating Systems
Green. The inspectors identified a Green, non-cited violation of Technical Specification 5.4.1
involving the failure to appropriately pre-plan and implement written procedures associated
with configuration control of the hazard barrier hydrogen guard piping in the proximity and
impacting safety-related equipment. This issue was entered into the licensee corrective
action program as Notification 50778755.
The inspectors determined that the failure to consider the impact to the fire hazard analysis
and the seismic configuration of the hydrogen guard pipe was a performance deficiency.
The performance deficiency was more than minor because it was associated with the
protection against external events attribute of the Mitigating Systems cornerstone and
adversely affected the cornerstone objective to ensure the availability, reliability, and
capability of systems (i.e. hazard barriers) that respond to initiating events, such as fires, to
prevent undesirable consequence. Though there were no actual consequences, the
breaching of the seismically qualified hydrogen guard piping removed a designed hazard
barrier and has the potential to vent hydrogen into rooms containing safety related
equipment. Using IMC 0609, Appendix F, Fire Protection Significance Determination
Process, Phase 1 Worksheet, the finding was determined to be of very low safety
significance (Green) because it represented a low degradation of fire prevention and
administrative controls element of the plant combustible material controls program, and the
breaching of the hydrogen guard piping would not have prevented the safe shutdown of the
plant. This finding has a cross-cutting aspect of design margins associated with the human
performance area. Specifically, the most significant contributor for the performance
deficiency was the licensee did not have an adequate work process that focused on
maintaining defense in depth related to a fire hazard barrier, such as a hydrogen guard
piping, during maintenance activities. Breaching hydrogen guard piping impacts defense in
depth and design margins used to protect safety-related equipment, and special attention is
required to carefully guard and change the configuration with great thought and care [H.6].
(Section 1R05)
Green - Severity Level IV. The inspectors reviewed a self-revealing, Severity Level IV
non-cited violation of 10 CFR 55.49, Integrity of Examinations and Tests, and an
associated Green finding for the licensees failure to provide adequate examination security
measures during administration of the 2015 biennial requalification examination. On
May 26, 2015, a licensed operator was able to obtain plant computer information that led to
the discovery of specific plant events contained on the NRC-required annual operating test.
The licensee entered this issue into the corrective action program as Notification 50704195
and retested the crew with a new scenario.
The failure of the licensee to provide adequate measures for examination security for the
biennial requalification examinations was a performance deficiency. The performance
deficiency was more than minor, and therefore a finding, because it adversely affected the
human performance attribute of the Mitigating Systems cornerstone objective of ensuring
the availability, reliability, and capability of systems that respond to initiating events to
prevent undesirable consequences. Using NRC Inspection Manual Chapter 0609,
Significance Determination Process, Attachment 4, Tables 1 and 2 worksheets (issue date
June 19, 2012); and the corresponding Appendix I, Licensed Operator Requalification
Significance Determination Process (SDP), Flowchart Block #10 (issue date
December 6, 2011), the finding was determined to have very low safety significance
(Green). Although the 2015 finding resulted in a compromise of the integrity of biennial
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dynamic simulator examinations had no compensatory actions been taken, the equitable
and consistent administration of the biennial dynamic simulator examination was not actually
affected by this compromise. The traditional enforcement violation was determined to be a
Severity Level IV violation consistent with Section 6.4.d of the Enforcement Policy. This
finding has a cross-cutting aspect in the resources component of the human performance
cross-cutting area because the licensee failed to ensure the procedures are adequate to
ensure nuclear safety [H.1]. (Section 1R11)
Green. The inspectors identified a Green, non-cited violation of 10 CFR Part 50,
Appendix B, Criterion III, Design Control, involving the licensees failure to ensure credited
design features, such as flow vent paths, protect safety-related systems, from temperature
and pressure effects of a high-energy line break (HELB) in the auxiliary building.
Specifically, the licensee allowed obstruction of a credited flow path with acrylic glass plates
not qualified in the original design and not verified to function under a HELB scenario. The
licensee entered this issue into the corrective action program as Notifications 50697910
and 50698102, and took immediate actions to remove the acrylic glass plates from the vent
path doors in the auxiliary building.
The performance deficiency was determined to be more than minor because it affected the
Mitigating Systems Cornerstone attribute of Design Control and adversely affected the
cornerstone objective of ensuring the reliability, availability and capability of systems that
respond to initiating events to prevent undesirable consequences. Specifically, the licensee
did not have adequate measures in place to ensure that qualified components were
available to mitigate the consequences of a HELB in the auxiliary building. The finding
screened as of very low safety significance (Green) because the finding did not affect the
design or qualification of mitigating structures, systems, and components; the finding did not
represent a loss of system and/or function; the finding did not represent an actual loss of a
function of a single train for greater than the technical specification (TS) allowed outage
time; the finding did not represent an actual loss of a function of one or more non-TS trains
of equipment; and did not screen as potentially risk significant due to a seismic, flooding, or
severe weather initiating event. The finding was not assigned a cross-cutting aspect since
the performance deficiency is not indicative of current plant performance. (Section 4OA2.4)
Green. The inspectors reviewed a self-revealing Green, non-cited violation of Technical
Specification 3.3.4 Remote Shutdown System, for the licensees failure to maintain
adequate configuration control of fuses associated with an emergency diesel generator
(EDG). The licensees failure to maintain adequate configuration control by not verifying
that fuses were properly installed, and adequate post maintenance testing was performed,
following maintenance activities was a performance deficiency. Specifically, following
the 1R17 refueling outage, from approximately June 13, 2013 until November 22, 2013,
EDG 1-3 would not have been able to perform its remote shutdown function due to not being
able to be adequately operated at the local EDG control cubicle. The licensee entered this
issue into the corrective action program as Notification 50595473, and took prompt actions
to restore the fuses to the correct position and verify the positions of the fuses in the other
EDG output breaker cubicles.
The failure to properly install fuses in the local manual operation circuitry of EDG 1-3 was a
performance deficiency. The performance deficiency was more than minor because it was
associated with the protection against external events (fire) attribute of the Mitigating
Systems Cornerstone, and it adversely affected the cornerstone objective of ensuring the
availability, reliability, and capability of systems that respond to initiating events to prevent
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undesirable consequences. Specifically, it affected the ability to reach and maintain safe
shutdown conditions in case of a fire causing a control room abandonment. The inspectors
evaluated this finding using Inspection Manual Chapter 0609, Appendix F, Fire Protection
Significance Determination Process," dated September 20, 2013. Because it affected the
ability to reach and maintain safe shutdown conditions in case of a fire that led to control
room evacuation, the Phase 2 methodology of Inspection Manual Chapter 0609,
Appendix F, was not appropriate for this finding. Therefore, the senior reactor analyst
performed a Phase 3 evaluation to determine the risk significance. The analyst determined
that the performance deficiency only increased the risk of the plant as it related to the need
to locally control EDG 1-3 following a postulated control room evacuation. The Senior Risk
Analyst determined that the change in core damage frequency was less than 1 x 10-6, and
the finding was not significant with respect to large, early release frequency. The analyst
determined that this finding was of very low risk significance (Green). This finding had a
cross-cutting aspect in the area of human performance associated with the work practices
component, because the licensee did not ensure supervisory and management oversight of
work activities, such that nuclear safety was supported [H.5]. (Section 4OA3.3)
Licensee-Identified Violations
Violations of Severity Level IV that were identified by the licensee have been reviewed by the
inspectors. Corrective actions taken or planned by the licensee have been entered into the
licensees corrective action program. These violations and associated corrective action tracking
numbers (notifications) are listed in Section 4OA7 of this report.
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PLANT STATUS
Units 1 and 2 operated at or near full power for the duration of this inspection period.
REPORT DETAILS
1.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and
1R01 Adverse Weather Protection (71111.01)
.1
Readiness for Impending Adverse Weather Conditions
a.
Inspection Scope
On April 7, 2015, the inspectors completed an inspection of the stations readiness for
impending adverse weather conditions. The inspectors reviewed plant design features,
the licensees procedures to respond to high winds and heavy rains, and the licensees
implementation of these procedures. The inspectors evaluated operator staffing and
accessibility of controls and indications for those systems required to control the plant.
These activities constituted one sample of readiness for impending adverse weather
conditions, as defined in Inspection Procedure 71111.01.
b.
Findings
No findings were identified.
.2
Readiness to Cope with External Flooding
a.
Inspection Scope
On May 13, 2015, the inspectors completed an inspection of the stations readiness to
cope with external flooding. After reviewing the licensees flooding analysis, the
inspectors chose two plant areas that were susceptible to flooding:
230 kV switchyard
500 kV switchyard
The inspectors reviewed plant design features and licensee procedures for coping with
flooding. The inspectors walked down the selected areas to inspect the design features,
including the material condition of seals, drains, and flood barriers. The inspectors
evaluated whether credited operator actions could be successfully accomplished.
These activities constituted one sample of readiness to cope with external flooding, as
defined in Inspection Procedure 71111.01.
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b.
Findings
No findings were identified.
1R04 Equipment Alignment (71111.04)
Partial Walkdown
a.
Inspection Scope
The inspectors performed partial system walk-downs of the following risk-significant
systems:
May 12, 2015, Unit 1, component cooling water
May 14, 2015, Unit 2, auxiliary salt water system
May 22-23, 2015, Unit 2, emergency diesel generator 2-2, fuel oil system
alignment
The inspectors reviewed the licensees procedures and system design information to
determine the correct lineup for the systems. They visually verified that critical portions
of the systems were correctly aligned for the existing plant configuration.
These activities constituted three partial system walk-down samples as defined in
Inspection Procedure 71111.04.
b.
Findings
No findings were identified.
1R05 Fire Protection (71111.05)
Quarterly Inspection
a.
Inspection Scope
The inspectors evaluated the licensees fire protection program for operational status
and material condition. The inspectors focused their inspection on five plant areas
important to safety:
April 16, 2015, Unit 1 and 2, auxiliary building 85 foot elevation radiological
control area
April 22, 2015, Units 1 and 2, cable spreading rooms
May 12, 2015, Unit 1, component cooling water heat exchanger room
May 22-23, 2015, Unit 2, turbine building areas located 104 foot elevation
June 23, 2015, Unit 2, emergency diesel generator rooms
- 9 -
For each area, the inspectors evaluated the fire plan against defined hazards and
defense-in-depth features in the licensees fire protection program. The inspectors
evaluated control of transient combustibles and ignition sources, fire detection and
suppression systems, manual firefighting equipment and capability, passive fire
protection features, and compensatory measures for degraded conditions.
These activities constituted five quarterly inspection samples, as defined in Inspection
Procedure 71111.05.
b.
Findings
Introduction. The inspectors identified a Green non-cited violation of Technical
Specification 5.4.1 involving the failure to appropriately pre-plan and implement written
procedures associated with configuration control of the hazard barrier hydrogen guard
piping in the proximity and impacting safety-related equipment. This issue was entered
into the licensee corrective action program as Notification 50778755.
Description. On January 29, 2015, inspectors observed planned work activity
associated with replacement of Unit 1, volume control tank hydrogen pressure-regulator
and pressure control valve PCV 955. Work Order WO 60075528, temporary work
procedure TP TO-15001, and clearance 1C19-D-08-025 were procedures for planning
and implementing the maintenance activity. The scope of the work directed the
replacement of the hydrogen regulator and required removal of hydrogen guard piping
cover plates to facilitate isolation of the volume control tank (VCT) hydrogen supply.
The current licensing bases at Diablo Canyon permit hydrogen supply pipes routed in
areas containing safety-related equipment only if the piping remains enclosed with a
seismically qualified guard pipe. The seismic design guard pipe is vented to the outside
and is required to be leak tight. The design allows an adequate vent path for the
hydrogen gas to minimize hazards from a hydrogen explosion.
The inspectors noted the Unit 1 hydrogen guard piping is routed in areas of the
auxiliary-control building which contained safety-related equipment. The work had
breached sealed cover plates used to maintain the venting path of the hydrogen gas to
minimize hazards from a hydrogen explosion. The inspector contacted the operations
shift manager to determine if the fire department was aware of the guard piping breach.
The shift manager was not aware of any notification that had been made to the fire
department and documented the inspector concerns in Notification 50684755.
Work Order 60075528 Replacing Unit 1 volume control tank regulator PCV 955, stated
in the Precautions and Limitations: hydrogen gas is present in system which constitutes
an explosive atmosphere hazard. The risk assessment, in accordance with station
procedure AD7 ID14, was evaluated on the impact to primary coolant chemistry, but not
with hazard barrier impact associated with fire hazard analysis. The work procedures
provided hazard material precautionary steps that included testing for hydrogen and use
of non-spark tooling.
On March 19, 2015, in response to the inspectors follow-up concerns on the fire hazard
and seismic configuration control, the licensee concluded the guard pipe was seismically
qualified to provide an additional level of defense in depth to prevent a potential
hydrogen build up in safety-related rooms or rooms with safe shutdown equipment. The
licensee also concluded the guard pipe is credited as a level hazard mitigation by the
- 10 -
Final Safety Analysis Report Update (FSARU) and other supporting documentation,
however, it is not considered a fire protection impairment per station procedure O8.ID2
which covers fire protection system barriers, suppression, detection, hose reels,
emergency lightings, etc. The licensee concluded that breaching of the system could
introduce a potential hazard if the hydrogen line itself failed and the excess flow shutoff
valves did not actuate.
On March 26, 2015, following the inspectors questions on the licensing basis of the
hydrogen guard piping, the licensee concluded the guard pipe is a unique plant feature
credited in the fire hazards analysis, but because it is not a fire barrier, it is not classified
as part of the Diablo Canyon fire protection system. This conclusion is documented in
Notification 50694348. In response to the licensee assessment of the function of the
hydrogen guard pipe, the inspectors determined the hydrogen guard piping is a hazard
barrier as described in the DCPP Units 1 and 2, FSARU Chapter 9.5A, Fire Hazard
Analysis. The hydrogen line in safety-related areas is design to be protected with a
guard pipe and is associated with in situ combustible materials as part of a system to
vent highly combustible hydrogen gas away from safety-related equipment.
On April 14, 2015, in response to the inspectors concerns regarding the seismic
configuration and controls related to Work Order WO 60075528, Notifications 50697654
and 50697655 were written to ensure requirements of the licensees seismic induced
system interactions program and seismic configuration control program were
appropriately evaluated.
Procedure AD7.DC8, Work Planning, Revision 45, which provides requirements for the
planning of maintenance, states in part:
Section 8.45.2, A fire protection engineer shall review orders for work on the fire
protection system or for work requiring planned impairments of the fire protection
system
Section 8.45.5, A piping engineer shall review orders that require dismantling
piping, piping components
Section 8.64, Seismic Configuration Control, states, in part, engineering
structural review is required on equipment within the seismic configuration control
program, such as the hydrogen guard piping, to ensure personnel do not
invalidate seismic qualification through engineering, construction, maintenance or
procurement activities
Section 8.65, Seismic Induced Systems Interaction Program (SISIP), has
requirements for planning work to ensure compliance with the SISIP.
Procedure AD4.ID3, Seismic induced system interaction program (SISIP)
Housekeeping Activities, Revision 14, states, in part:
Maintenance activities that create potential seismic induced system interactions
such as parts resulting from equipment disassembly (i.e., removing cover plates
from hydrogen guard piping) are required to be identified and evaluated.
Procedure OM8, Fire Protection Program, provides elements to ensure the design of
systems, components and structures shall minimize consequences and provide for safe
- 11 -
shutdown in case of fire. The fire protection program brings together diverse elements in
order to meet the goal of defense in depth fire safety. As stated in Section 4.4, Design
and Modification Control, fire protection program will:
Preclude modifications to plant design which adversely affect fire
detection/suppression equipment, fire-rated barriers and the fire hazards
analysis.
The inspectors determined that the hydrogen guard piping, because it is documented in
the fire hazard analysis section of Diablo Canyon FSARU section 9.5.1, and fire
protection systems are based on known configurations that include both active and the
passive fire protection element (such as hydrogen guard), is integral to the licensees
defense in depth design to assure safe shutdown following a design basis fire.
The inspectors also determined that hydrogen guard piping represents a component with
a certain design margin as equipment important to both roles as a fire hazard barrier and
its seismic configuration. When maintenance is not properly performed, this design
margin is changed which may impact safety-related equipment.
The licensee documented evaluation of NRC Generic Letter 93-06, Highly Combustible
Gas in Vital Areas, in Action Request A0332316; dated December 13, 1995, which
states, in part:
The Guard Pipe is really a ventilation duct which routes any leak in the guarded
hydrogen pipe to outside the building.
In the same response, the licensee evaluation stated, To further minimize hazards from
a hydrogen explosion, hydrogen lines will be rerouted out of certain areas containing
safety-related equipment and will be enclosed within a guarded pipe where its runs in
any areas containing safety-related equipment. The guard pipe will be vented to the
outdoors and will be pressure tested to verify that it is leak tight. Based on this
assessment, the inspectors concluded the hydrogen guard pipe represents a fire hazard
barrier since safety evaluation (SER #8) approved by the NRC on November 15, 1978,
required fire zones containing hydrogen lines be provided with seismic Category I Guard
Pipes installed around these hydrogen lines prior to plant operations.
Analysis. The inspectors determined that the failure to consider the impact to the fire
hazard analysis and the seismic configuration of the hydrogen guard pipe was a
performance deficiency. The inspectors evaluated the performance deficiency in
accordance with Inspection Manual Chapter 0612, Appendix B, Issue Screening. The
performance deficiency was more than minor because it was associated with the
protection against external events attribute of the Mitigating Systems cornerstone and
adversely affected the cornerstone objective to ensure the availability, reliability, and
capability of systems (i.e., hazard barriers) that respond to initiating events, such as
fires, to prevent undesirable consequence. Though there were no actual consequences,
the breaching of the seismically qualified hydrogen guard piping removed a designed
hazard barrier and has the potential to vent hydrogen into rooms containing
safety-related equipment. Using IMC 0609, Appendix F, Fire Protection Significance
Determination Process, Phase 1 Worksheet, the finding was determined to be of very
low safety significance (Green) because it represented a low degradation of fire
prevention and administrative controls element of the plant combustible material controls
- 12 -
program, and the breaching of the hydrogen guard piping would not have prevented the
safe shutdown of the plant.
This finding has a cross-cutting aspect of design margins associated with the human
performance area. Specifically, the most significant contributor for the performance
deficiency was the licensee did not have an adequate work process that focused on
maintaining defense in depth related to a fire hazard barrier, such as a hydrogen guard
piping, during maintenance activities. Breaching hydrogen guard piping impacts defense
in depth and design margins used to protect safety-related equipment, and special
attention is required to carefully guard and change the configuration with great thought
and care [H.6].
Enforcement. Technical Specification 5.4.1.a, states, in part, that Written procedures
shall be established, implemented, and maintained covering the following activities: the
applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A,
February 1978. Regulatory Guide 1.33, Appendix A, Section 9, states, in part,
Maintenance that can affect the performance of safety-related equipment should be
properly pre-planned and performed in accordance with written procedures, documented
instructions, or drawings appropriate to the circumstances. Procedure AD7.DC8 Work
Planning, requires planning of maintenance to consider areas such as fire protection
hazards, seismic induced system interactions, and changes to seismic configuration of
plant components. Contrary to the above, on January 29, 2015, the licensee failed to
properly pre-plan and perform appropriate evaluation prior to maintenance on equipment
that can affect the performance of safety-related equipment in accordance with the
requirements of Procedure AD7.DC8 Work Planning. Specifically, the licensee
directed operators to perform work on hydrogen guard piping that did not properly
evaluate the impact of the hydrogen guard piping hazard barrier breach. The violation
did not result in any actual consequences, but breaching of the hydrogen guard piping
can introduce a potential fire hazard if the non-seismic hydrogen line leaks. Corrective
actions included revision to work instructions to include notification of fire department of
the breach of the hydrogen guard piping. In addition, work-planning procedures were
revised to ensure properly preplanning and coordination between fire protection and civil
engineering prior to conducting maintenance activities on hydrogen piping.
Because this violation was of very low safety significance and it was entered into the
licensees corrective action program as Notification 50778755, this violation is being
treated as a non-cited violation, consistent with Section 2.3.2.a of the NRC Enforcement
Policy: NCV 05000275/2015002-01, "Failure to Appropriately Pre-plan and Perform
Maintenance on Hydrogen Guard Piping.
1R06 Flood Protection Measures (71111.06)
a.
Inspection Scope
On April 16, 2015, the inspectors completed an inspection of the stations ability to
mitigate flooding due to internal causes. After reviewing the licensees flooding analysis,
the inspectors chose one plant area containing risk-significant structures, systems, and
components that were susceptible to flooding:
April 14-16, 2015, Unit 1 and 2, auxiliary building 85 foot elevation
- 13 -
The inspectors reviewed plant design features and licensee procedures for coping with
internal flooding. The inspectors walked down the selected areas to inspect the design
features, including the material condition of seals, drains, and flood barriers. The
inspectors evaluated whether operator actions credited for flood mitigation could be
successfully accomplished.
These activities constitute completion of one flood protection measures sample, as
defined in Inspection Procedure 71111.06.
b.
Findings
No findings were identified.
1R11 Licensed Operator Requalification Program and Licensed Operator Performance
(71111.11)
.1
Review of Licensed Operator Requalification
a.
Inspection Scope
On June 18, 2015, the inspectors observed a portion of an annual requalification exam
for a licensed operating crew. The inspectors assessed the simulator and licensed
operator performance during an exam scenario and the corresponding evaluators
critique following the exam scenario. The inspectors also assessed a portion of an
annual requalification test for licensed operators and evaluated a simulator scenario
performed by an operating crew.
These activities constitute completion of one quarterly licensed operator requalification
program sample, as defined in Inspection Procedure 71111.11.
b.
Findings
No findings were identified.
.2
Review of Licensed Operator Performance
a.
Inspection Scope
The inspectors observed the performance of on-shift licensed operators in the plants
main control room. At the time of the observations, the plant was in a period of
heightened activity. The inspectors observed the operators performance of the following
activities:
May 6, 2015, Unit 2, down power and ascension to full power for turbine valve
testing
June 29, 2015, Unit 1, alarm response due to failed power supply IY-19
In addition, the inspectors assessed the operators adherence to plant procedures,
including and other operations department policies.
- 14 -
These activities constitute completion of two quarterly licensed operator performance
samples, as defined in Inspection Procedure 71111.11.
b.
Findings
No findings were identified.
.3
Biennial Review of Requalification Program
The licensed operator requalification program involves two training cycles that are
conducted over a two-year period. In the first cycle, the annual cycle, the operators are
administered an operating test consisting of job performance measures and simulator
scenarios. In the second part of the training cycle, the biennial cycle, operators are
administered an operating test and a comprehensive written examination.
a.
Inspection Scope
To assess the performance effectiveness of the licensed operator requalification
program, the inspectors conducted personnel interviews, reviewed both the operating
tests and written examinations, and observed ongoing operating test activities.
The inspectors reviewed operator performance on the written exams and operating
tests. These reviews included observations of portions of the operating tests by the
inspectors. The operating tests observed included 22 job performance measures
and 3 scenarios that were used in the current biennial requalification cycle. These
observations allowed the inspectors to assess the licensee's effectiveness in conducting
the operating test to ensure operator mastery of the training program content. The
inspectors also reviewed medical records of 11 licensed operators for conformance to
license conditions and the licensees system for tracking qualifications and records of
license reactivation for 8 operators.
The results of these examinations were reviewed to determine the effectiveness of the
licensees appraisal of operator performance and to determine if feedback of
performance analyses into the requalification training program was being accomplished.
The inspectors interviewed members of the training department and reviewed minutes of
training review group meetings to assess the responsiveness of the licensed operator
requalification program to incorporate the lessons learned from both plant and industry
events. Examination results were also assessed to determine if they were consistent
with the guidance contained in NUREG 1021, "Operator Licensing Examination
Standards for Power Reactors," Revision 9, Supplement 1, and NRC Inspection Manual
Chapter 0609, Appendix I, "Operator Requalification Human Performance Significance
Determination Process."
In addition to the above, the inspectors reviewed examination security measures,
simulator fidelity, and existing logs of simulator deficiencies.
On June 10, 2015, the licensee informed the inspectors of the completed cycle results
for Unit 1 and 2 for both the written examinations and the operating tests:
14 of 16 crews passed the simulator portion of the operating test
- 15 -
81 of 87 licensed operators passed the simulator portion of the operating test
84 of 85 licensed operators passed the job performance measure portion of the
operating test
85 of 85 licensed operators passed the written examination
The individuals that failed the simulator scenario and/or job performance measure
portions of the operating test were remediated, retested, and passed their retake
examinations prior to returning to licensed duties. Individuals who did not complete the
requalification examination during the requalification cycle were administratively
restricted from performing licensed duties until they had successfully completed a
requalification examination.
The inspectors completed one inspection sample of the biennial licensed operator
requalification program.
b.
Findings
Introduction. The inspectors reviewed a self-revealing Severity Level IV, non-cited
violation of 10 CFR 55.49, Integrity of Examinations and Tests, and an associated
Green finding for the licensees failure to provide adequate examination security
measures during administration of the 2015 biennial requalification examination. On
May 26, 2015, a licensed operator was able to obtain plant computer information that led
to the discovery of specific plant events contained on the NRC-required annual operating
test. The licensee entered this into their corrective action program as
Notification 50704195 and retested the crew with a new scenario.
Description. The licensee was in the process of administering the dynamic simulator
portion of the 2015 biennial requalification examination. The scenario was to be
administered to three separate crews during the day. The first crew performed the
scenario and during the course of the evaluation created plant trends for plant
parameters that were needed to monitor the plant for specific events using the plant
computer. The first run of the scenario was completed and the simulator was reset
using the guidance in Procedure TQ2.ID4, Training Program Implementation.
The second crew entered the simulator and commenced their board walkdowns.
During the board walkdowns, a licensed operator was setting plant computer screens to
monitor desired parameters during the upcoming session. The operator discovered that
the plant parameters and range values that the previous crew had established during the
first run of the simulator scenario were visible and was able to determine the likely plant
events that were going to be on his examination. Upon being notified of the possible
examination security compromise, the licensee took immediate corrective action,
invalidated the scenario for the affected crew, and administered an alternate scenario.
The licensee also provided interim guidance to modify the exam security for the
simulator plant computer to ensure that type of information is not available in the future.
The examination security compromise was entered into the licensees corrective action
program as Notification 50704195.
The licensee evaluated the examination security for the entire biennial examination
cycle to determine the effect on the equitable and consistent administration of the
examination and previous examinations. This evaluation was submitted to the NRC
- 16 -
on June 10, 2015. The evaluation consisted of interviews that randomly selected two
members of every R147 Biennial NRC examination simulator group, with one member
from the management team and one member from the bargaining unit population of
licensed operators. The interviews were used to determine if, during board walkdowns,
they had encountered any indications such as plant computer screens, inappropriately
filed procedures, or various forms of control board flagging that allowed them to
determine any events in the scenarios given. The result was that no licensed operator
had encountered any such information. The plant computer vulnerability was
determined to have exist since 2008 when the plant computer was upgraded. An
independent review of the past 10 years of annual and biennial inspections was
conducted by NRC staff and there was no indication of changes in examination
performance since the specific vulnerability was introduced in 2008. Based on this
review and the interview results provided by the facility, the inspectors determined there
is no indication that the exam security vulnerability introduced in 2008 had an actual
effect on the results of the current or previous NRC-required examinations.
Analysis. The failure of the licensee to provide adequate measures for examination
security for the biennial requalification examinations was a performance deficiency. The
failure also constitutes a violation of 10 CFR 55.49, which was evaluated through the
traditional enforcement process. The significance determination process, which was
used to evaluate this performance deficiency, does not specifically consider a
performance deficiencys impact on the regulatory process. Thus, although related to a
common regulatory concern, it is necessary to address both the violation and finding
using different processes to correctly reflect both the regulatory importance of the
violation and the safety significance of the associated performance deficiency.
The performance deficiency was more than minor, and therefore a finding, because
it adversely affected the human performance attribute of the Mitigating Systems
cornerstone objective of ensuring the availability, reliability, and capability of
systems that respond to initiating events to prevent undesirable consequences.
Additionally, if left uncorrected, the performance deficiency could have become more
significant in that allowing licensed operators to return to the control room without valid
demonstration of appropriate knowledge on the biennial written examinations could be
a precursor to a more significant event. Using NRC Inspection Manual Chapter 0609,
Significance Determination Process, Attachment 4, Tables 1 and 2 worksheets (dated
June 19, 2012); and the corresponding Appendix I, Licensed Operator Requalification
Significance Determination Process (SDP), Flowchart Block #10 (dated
December 6, 2011), the finding was determined to have very low safety significance
(Green). Although the 2015 finding resulted in a compromise of the integrity of biennial
dynamic simulator examinations had no compensatory actions been taken, the equitable
and consistent administration of the biennial dynamic simulator examination was not
actually affected by this compromise.
The failure of the licensee to meet 10 CFR 55.49 requirements was determined to be a
Severity Level IV (SL-IV) violation. This is based on the failure to fully delete trend
parameter and range information from the simulated plant computer being a non-willful
compromise of an examination required by 10 CFR Part 55, that did not contribute to the
NRC making an incorrect regulatory decision. This is consistent with Section 2.2.4 and
Section 6.4.d of the NRC Enforcement Policy (issued June 7, 2012).
- 17 -
This finding has a cross-cutting aspect in the resources component of the human
performance cross-cutting area because the licensee failed to ensure the procedures
are adequate to ensure nuclear safety. After a licensee procedure review was
conducted, the licensee concluded that a programmatic issue existed in that the
simulator examination security checklist in TQ2.ID4, Training Program Implementation,
did not provide sufficient information to ensure the simulated plant computer was fully
cleared of plant trend parameters and range [H.1].
Enforcement. Title 10 of the Code of Federal Regulations (10 CFR) 55.49, Integrity of
Examinations, requires, in part, that facility licensees shall not engage in any activity
that compromises the integrity of any application, test, or examination. The integrity of a
test or examination is considered compromised if any activity, regardless of intent,
affected or, but for detection, would have affected the equitable and consistent
administration of the test or examination. Contrary to the above, from 2008 to
May 26, 2015, the licensee engaged in an activity that compromised the integrity of the
examination administered on May 26, 2015. Specifically, an operator discovered plan
parameters and range values that the previous crew had established and was able to
determine the likely plant events that were going to be used in simulator examination.
Upon discovery of the compromised examination, the licensee invalidated the scenario
for the affected crew and administered an alternate scenario.
The inspectors determined that the compromise of the 2015 biennial simulator
examination did not result in an actual effect on the equitable and consistent
administration of the examination. Because this finding is of very low safety
significance and has been entered into the licensees corrective action program
as Notification 50704195 to address recurrence, this violation is being treated as a
non-cited violation consistent with Section 2.3.2 of the NRC Enforcement Policy:
NCV 05000275/2015002-02; 05000323/2015002-02, Failure to Maintain Operator
Licensing Examination Integrity.
1R12 Maintenance Effectiveness (71111.12)
a.
Inspection Scope
The inspectors reviewed three instances of degraded performance or condition of
safety-related structures, systems, and components (SSCs):
April 18-22, 2015, Unit 2, emergency diesel generator (2-2) programmable
controller timer failure
April 20-22, 2015, Unit 2, emergency diesel generator cap screws replacement
June 30, 2015, 230 kV and 500 kV equipment reliability activities
The inspectors reviewed the extent of condition of possible common cause SSC failures
and evaluated the adequacy of the licensees corrective actions. The inspectors
reviewed the licensees work practices to evaluate whether these may have played a
role in the degradation of the SSCs. The inspectors assessed the licensees
characterization of the degradation in accordance with 10 CFR 50.65 (the Maintenance
Rule), and verified that the licensee was appropriately tracking degraded performance
and conditions in accordance with the Maintenance Rule.
- 18 -
These activities constituted completion of three maintenance effectiveness samples, as
defined in Inspection Procedure 71111.12.
b.
Findings
No findings were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)
a.
Inspection Scope
The inspectors reviewed three risk assessments performed by the licensee prior to
changes in plant configuration and the risk management actions taken by the licensee in
response to elevated risk:
April 28-30, 2015, Unit 1 and 2, 230 kV switchyard activities for planned
maintenance on high voltage insulators and site startup power
May 11, 2015, Unit 2, auxiliary salt water screen replacement
June 29, 2015, Unit 2, emergency diesel generator 2-2 planned maintenance
The inspectors verified that these risk assessment were performed timely and in
accordance with the requirements of 10 CFR 50.65 (the Maintenance Rule) and plant
procedures. The inspectors reviewed the accuracy and completeness of the licensees
risk assessments and verified that the licensee implemented appropriate risk
management actions based on the result of the assessments.
The inspectors also observed portions of three emergent work activities that had the
potential to cause an initiating event, or to affect the functional capability of mitigating
systems:
April 22-23, 2015, Unit 1 and 2, clearance of carbon dioxide fire suppression
system for hose reel replacement
May 20, 2015, Unit 2, power operated relief valve downstream tailpipe
temperature setpoint change
June 21-22, 2015, Unit 1, emergency diesel generator 1-2 planned maintenance
The inspectors verified that the licensee appropriately developed and followed a work
plan for these activities. The inspectors verified that the licensee took precautions to
minimize the impact of the work activities on unaffected structures, systems, and
components (SSCs).
These activities constitute completion of six maintenance risk assessments and
emergent work control inspection samples, as defined in Inspection Procedure 71111.13.
b.
Findings
No findings were identified.
- 19 -
1R15 Operability Determinations and Functionality Assessments (71111.15)
a.
Inspection Scope
The inspectors reviewed six operability determinations that the licensee performed for
degraded or nonconforming structures, systems, or components (SSCs):
April 1-3, 2015, operability determination of Unit 1, plant vent normal range
radiation monitor RM-24, incorrect input to source term data to emergency plan
management system
April 6-8, 2015, operability determination of Unit 2, auxiliary feedwater pump 2-3,
discharge header piping wear
April 16-17, 2015, operability determination of reactor coolant leak detection
monitoring
April 23, 2015, Unit 2, operability determination of high pressure turbine reheat
steam leakage
May 18, 2015 Unit 2 operability determination of pressurizer relief tank
pressurization
May 26, 2015, operability determination of emergency diesel generator hurricane
barrier corrosion
The inspectors reviewed the timeliness and technical adequacy of the licensees
evaluations. Where the licensee determined the degraded SSC to be operable, the
inspectors verified that the licensees compensatory measures were appropriate to
provide reasonable assurance of operability. The inspectors verified that the licensee
had considered the effect of other degraded conditions on the operability of the
degraded SSC.
These activities constitute completion of six operability and functionality review samples,
as defined in Inspection Procedure 71111.15.
b.
Findings
No findings were identified.
1R18 Plant Modifications (71111.18)
a.
Inspection Scope
The inspectors reviewed two temporary plant modifications that affected risk-significant
structures, systems, and components (SSCs):
May 12, 2015, Unit 1, auxiliary salt water system screen replacement
May 20, 2015, Unit 2, power operation relief valve downstream tailpipe
temperature setpoint change
- 20 -
The inspectors verified that the licensee had installed these temporary modifications in
accordance with technically adequate design documents. The inspectors verified that
these modifications did not adversely impact the operability or availability of affected
SSCs. The inspectors reviewed design documentation and plant procedures affected by
the modifications to verify the licensee maintained configuration control.
These activities constitute completion of two samples of temporary modifications, as
defined in Inspection Procedure 71111.18.
b.
Findings
No findings were identified.
1R19 Post-Maintenance Testing (71111.19)
a.
Inspection Scope
The inspectors reviewed five post-maintenance testing activities that affected
risk-significant structures, systems, or components (SSCs):
April 30, 2015, Unit 1, pressurizer heater group 1-2 supply breaker and control
switch maintenance testing description
May 12-13, 2015, Unit 1 and 2, test of diesel fuel oil transfer pump following
transfer switch maintenance
May 19, 2015, Unit 1, auxiliary salt water system following screen replacement
May 27-28, 2015, Unit 1, containment cooling unit fan 1-5 relay replacement
June 30, 2015, Unit 2, emergency diesel generator following maintenance
The inspectors reviewed licensing- and design-basis documents for the SSCs and the
maintenance and post-maintenance test procedures. The inspectors observed the
performance of the post-maintenance tests to verify that the licensee performed the tests
in accordance with approved procedures, satisfied the established acceptance criteria,
and restored the operability of the affected SSCs.
These activities constitute completion of five post-maintenance testing inspection
samples, as defined in Inspection Procedure 71111.19.
b.
Findings
No findings were identified.
- 21 -
1R22 Surveillance Testing (71111.22)
a.
Inspection Scope
The inspectors observed six risk-significant surveillance tests and reviewed test results
to verify that these tests adequately demonstrated that the structures, systems, and
components (SSCs) were capable of performing their safety functions:
In-service tests:
April 9, 2015, Unit 1, auxiliary saltwater pump 1-1, comprehensive testing
May 6, 2015, Unit 2, turbine valve testing
Reactor coolant system leak detection tests:
May 14, 2015, Unit 2, power operated relief and block valve leakage
determination
Other surveillance tests:
April 1, 2015, Unit 1, train B, solid state protection system actuation logic and
safety injection reset timer slave relay K602 testing
April 22, 2015, Unit 1, protection set 3 channel operational test
May 22-23, 2015, Unit 2, emergency diesel generator 2-2, biennial 24-hour load
and hot test
The inspectors verified that these tests met technical specification requirements, that the
licensee performed the tests in accordance with their procedures, and that the results of
the test satisfied appropriate acceptance criteria. The inspectors verified that the
licensee restored the operability of the affected SSCs following testing.
These activities constitute completion of six surveillance testing inspection samples, as
defined in Inspection Procedure 71111.22.
b.
Findings
No findings were identified.
Cornerstone: Emergency Preparedness
1EP6 Drill Evaluation (71114.06)
Emergency Preparedness Drill Observation
a.
Inspection Scope
The inspectors observed an emergency preparedness drill on June 10, 2015, to verify
the adequacy and capability of the licensees assessment of drill performance. The
inspectors reviewed the drill scenario, observed the drill from the Technical Support
Center and Operations Support Center, and reviewed the post-drill critique. The
inspectors verified that the licensees emergency classifications, off-site notifications,
and protective action recommendations were appropriate and timely. The inspectors
verified that any emergency preparedness weaknesses were appropriately identified by
- 22 -
the licensee in the post-drill critique and entered into the corrective action program for
resolution.
These activities constitute completion of one emergency preparedness drill observation
sample, as defined in Inspection Procedure 71114.06.
b.
Findings
No findings were identified.
4.
OTHER ACTIVITIES
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency
Preparedness, Public Radiation Safety, Occupational Radiation Safety, and
Security
4OA1 Performance Indicator Verification (71151)
.1
Safety System Functional Failures (MS05)
a.
Inspection Scope
For the period of January 1, 2014 through March 31, 2015, the inspectors reviewed
licensee event reports (LERs), maintenance rule evaluations, and other records that
could indicate whether safety system functional failures had occurred. The inspectors
used definitions and guidance contained in Nuclear Energy Institute Document 99-02,
Regulatory Assessment Performance Indicator Guideline, Revision 7, and
NUREG-1022, Event Reporting Guidelines: 10 CFR 50.72 and 50.73, Revision 3, to
determine the accuracy of the data reported.
These activities constituted verification of the safety system functional failures
performance indicator for Units 1 and 2, as defined in Inspection Procedure 71151.
b.
Findings
No findings were identified.
.2
Mitigating Systems Performance Index: Emergency AC Power Systems (MS06)
a.
Inspection Scope
The inspectors reviewed the licensees mitigating system performance index data for the
period of January 1, 2014 through March 31, 2015, to verify the accuracy and
completeness of the reported data. The inspectors used definitions and guidance
contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment
Performance Indicator Guideline, Revision 7, to determine the accuracy of the reported
data.
These activities constituted verification of the mitigating system performance index for
emergency AC power systems for Units 1 and 2, as defined in Inspection
Procedure 71151.
- 23 -
b.
Findings
No findings were identified.
.3
Mitigating Systems Performance Index: High Pressure Injection Systems (MS07)
a.
Inspection Scope
The inspectors reviewed the licensees mitigating system performance index data for the
period of January 1, 2014 through March 31, 2015, to verify the accuracy and
completeness of the reported data. The inspectors used definitions and guidance
contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment
Performance Indicator Guideline, Revision 7, to determine the accuracy of the reported
data.
These activities constituted verification of the mitigating system performance index for
high pressure injection systems for Units 1 and 2, as defined in Inspection
Procedure 71151.
b.
Findings
No findings were identified.
4OA2 Problem Identification and Resolution (71152)
.1
Routine Review
a. Inspection Scope
Throughout the inspection period, the inspectors performed daily reviews of items
entered into the licensees corrective action program. The inspectors verified that
licensee personnel were identifying problems at an appropriate threshold and entering
these problems into the corrective action program for resolution. The inspectors verified
that the licensee developed and implemented corrective actions commensurate with the
significance of the problems identified. The inspectors also reviewed the licensees
problem identification and resolution activities during the performance of the other
inspection activities documented in this report.
b. Findings
No findings were identified.
.2
Semiannual Trend Review
a. Inspection Scope
The inspectors reviewed the licensees corrective action program, performance
indicators, system health reports, and other documentation to identify trends that might
indicate the existence of a more significant safety issue. The inspectors reviewed the
Licensing Basis Verification Project (LBVP) to assess whether this project was
continuing to identify and resolve historical conflicts in the licensing basis
documentation.
- 24 -
These activities constitute completion of one semiannual trend review sample, as
defined in Inspection Procedure 71152.
b. Observations
The LBVP is a significant initiative that PG&E committed to the NRC in order to identify
and resolve numerous historical conflicts in the licensing basis documentation. The
licensees expansion of the LBVP to include reviewing the licensing bases of Diablo
Canyons Emergency Preparedness Program to identify weaknesses and potential non-
conformances is appropriate in light of the White finding (Final Significance
Determination of White Finding and Notice of Violation; Diablo Canyon Nuclear Power
Plant - NRC Emergency Preparedness Inspection Report 05000275/2015502 and
05000323/2015502). At the close of the inspection period, the licensee had not
completed the project.
c. Findings
No findings were identified.
.3
Annual Follow-up of Selected Issues
a. Inspection Scope
The inspectors selected one issue for an in-depth follow-up:
May 29, 2015, Unit 2, power operated relief valve and block valve leakage
The inspectors assessed the licensees problem identification threshold, cause analyses,
extent of condition reviews and compensatory actions. The inspectors verified that the
licensee appropriately prioritized the planned corrective actions and that these actions
were adequate to for continued operation with degraded valves in accordance with
technical specification requirements.
These activities constitute completion of one annual follow-up sample as defined in
b. Findings
No findings were identified.
- 25 -
.4
Selected Issue Follow-up Inspection
a. Inspection Scope
The inspectors reviewed the licensees fire barrier, doors and high-energy line break
(HELB) program including the corrective action program to identify trends that might
indicate the existence of a more significant safety issue. The inspectors verified that the
licensee was taking corrective actions to address identified adverse trends related to fire
doors and barriers. Specifically, the inspectors noted that signage on doors were
missing and not correct.
These activities constitute completion of one semiannual trend review sample, as
defined in Inspection Procedure 71152.
b. Observations
The inspectors completed numerous plant inspections during the first half of 2015
evaluating fire doors and barriers. The inspectors also reviewed the licensee high
energy line break program which is integral to the licensee fire door program. Following
several observations by the inspectors it was identified that some HELB vent flow paths
were being obstructed. The licensee took immediate actions to remove the obstruction
and remove erroneous door signs.
c. Findings
Introduction. The inspectors identified a Green, non-cited violation of 10 CFR Part 50,
Appendix B, Criterion III, Design Control, involving the licensees failure to ensure
credited design features, such as flow vent paths, protect safety-related systems, from
temperature and pressure effects of a HELB in the auxiliary building. Specifically, the
licensee allowed obstruction of a credited flow path with acrylic glass plates not qualified
in the original design and not verified to function under a HELB scenario.
Description. On April 16, 2015, the inspectors, on a plant tour in the auxiliary building,
observed various fire protection doors were not consistently labelled. In addition, the
inspectors noted certain HELB vent-type doors, such as grated doors to letdown and
seal injection heat exchanger rooms, were designated as vent paths. These vent path
doors, located on the 85 foot elevation, were specifically designed with grated-style
panels so a continuous vent path is maintain between rooms in the auxiliary building.
The door signage on these vent path doors was incorrect because it stated that the
grated door was a HELB boundary door and should remain closed. However, the
inspectors found the doors open. The inspectors also identified that all of the
grated-style doors to rooms in the auxiliary building were covered with one-quarter-inch
thick acrylic glass plates that were firmly attached to the grating with plastic tie-wraps.
The inspectors reported these issues and requested additional information regarding the
engineering analysis that allowed the grated doors, a credited design vent path, to be
blocked with acrylic glass plates. The inspectors concerns with incorrect signage were
documented in Notification 50697910, and concerns regarding the blocked HELB vent
doors were documented in Notification 50698102. Immediate actions were taken to
remove the acrylic glass plates and incorrect signage from the vent path doors in the
auxiliary building.
- 26 -
On April 20, 2015, the inspectors concerns were evaluated further in
Notification 50698455. The licensee response identified that a design change was
added using design change package DCP M-49919, dated November 27, 2007. Part of
this design change establishes the potential reduction of HELB compartment vent flow
areas due to panel installations at the grated doors but assumed grated door were
covered with plastic sheets. The design change assumed these plastic sheets would
blow off during a HELB event. However, the licensee analysis on covering and blocking
the grated vent doors was qualitative and did not describe specific requirements and
limitations for the plastic sheets. On July 6, 2015, the licensee identified the equipment
functional location information contained in the design technical notes was erroneous.
Notification 50710846 documented this as a contributing factor for allowing a door
configuration outside the design requirements. The technical note, dated
October 5, 2007, states, in part, it is acceptable to have a plastic cover on this doors.
The note also refers to a design change and evaluation which was determined to be
inadequate.
The inspectors determined DCPP FSAR Update, Revision 22, Section 3.6.4.3,
High-Energy Piping Breaks Outside Containment, and Section 3.11, Environmental
Design of Mechanical and Electrical Equipment, provides design requirements to
protect safety-related structures, systems and components (SSCs) from the dynamic
effects of a HELB and the equipment qualification requirements for SSCs in a harsh
environment. In addition, pressurization of compartments with grated doors was part of
the analysis and was included in design calculation M-493, Areas H & K Pressures and
Temperatures in Auxiliary Building due to Pipe Breaks. Following a HELB, the rapid
introduction of steam increases the pressure and temperature in the compartment.
These conditions will propagate from the break through available flow paths. The
inspectors determined that the safety function of the grated doors, as a credited flow
path out of the heat exchanger rooms and to relieve the break flow and maintain
pressure and temperature, was actually invalidated by the obstruction of acrylic glass
plates.
Because of the inspectors concerns on the adequacy of the design, the licensee
performed a past operability evaluation which was documented in Notification 50698455.
The licensee identified: The [HELB] analysis was potentially invalidated by obstructions
on two credited flow paths out of the heat exchanger room (Doors 176A&B (U1) and
Doors 184A&B (U2)). Although placing plastic sheet on the outside of these doors was
evaluated to blow out by engineering judgement, there were no design details that
provided design requirements or limitations.
The inspectors determined that, in November 2007, engineering judgement was used
that allowed the grated doors to be obstructed with plastic tarp materials; it was judged
to be acceptable, but the inspectors determined that a qualified engineering analysis
was not done for placement of the one-quarter-inch thick acrylic glass plates using
plastic tie-wraps.
On May 13, 2015, because of the inspectors concerns, the licensee performed
extensive in-situ testing and determined that acrylic covers held with plastic tie-wraps
would not have invalidated the HELB analysis found in design calculations M-493.
- 27 -
Analysis. The inspectors determined that the failure to ensure credited design features,
such as flow vent paths, protect safety-related systems, from temperature and pressure
effects of a HELB in the auxiliary building was a performance deficiency. The
performance deficiency was determined to be more than minor because it affected the
Mitigating Systems Cornerstone attribute of Design Control and adversely affected the
cornerstone objective of ensuring the reliability, availability and capability of systems that
respond to initiating events to prevent undesirable consequences. Specifically, the
licensee did not have adequate measures in place to ensure that qualified components
were available to mitigate the consequences of a HELB in the auxiliary building
Using IMC 0609, Appendix A, issued June 19, 2012, The Significance Determination
Process (SDP) for Findings At-Power, the inspectors determined that the finding was of
very low safety significance (Green) because the finding did not affect the design or
qualification of mitigating structures, systems, and components; the finding did not
represent a loss of system and/or function; the finding did not represent an actual loss of
a function of a single train for greater than the technical specification (TS) allowed
outage time; the finding did not represent an actual loss of a function of one or more
non-TS trains of equipment; and did not screen as potentially risk-significant due to a
seismic, flooding, or severe-weather initiating event. Specifically, the licensee performed
an analysis that concluded the environmental qualifications of the safety-related
equipment in the auxiliary building would not be exceeded by a HELB in the auxiliary
building.
The finding was not assigned a cross-cutting aspect since the performance deficiency is
not indicative of current plant performance.
Enforcement. Title 10 of the Code of Federal Regulations (10 CFR) Part 50,
Appendix B, Criterion III, Design Control, requires, in part, that design control
measures shall provide for verifying or checking the adequacy of design, such as by the
performance of design reviews, by the use of alternate or simplified calculational
methods, or by performance of a suitable testing program. Contrary to the above, from
November 27, 2007, until April 20, 2015, Design Calculation Package C-47451 used
non-conservative assumptions, which did not appropriately verify the obstruction to
HELB compartment vent flow path would have maintained the environmental
qualification of safety-related equipment in the auxiliary building. The licensee validated
the condition by performing an in-situ analysis of the glass plate and tie-wraps in order to
determine whether the acrylic glass panels would have blown off during a HELB and,
therefore, would not have resulted in impact to environmental qualification assumptions.
Because this finding is of very low safety significance (Green) and was entered into the
licensees corrective action program as Notification 50698455, this violation is being
treated as a non-cited violation consistent with Section 2.3.2.a of the NRCs
Enforcement Policy: NCV 05000275/2015002-03; 05000323/2015002-03, Inadequate
Design Control for High-Energy Line Break Vent Flow Path.
4OA3 Follow-up of Events and Notices of Enforcement Discretion (71153)
.1
(Closed) Licensee Event Report (LER) 05000275; 05000323/2014-003-02: Unanalyzed
Condition Affecting Unit 1 and 2 Emergency Diesel Generators, Tornado Missiles
On March 6, 2014, as part of the LBVP, the licensee identified an unanalyzed condition
where the EDG exhaust plenums and exhaust piping were not adequately protected
- 28 -
from tornado missiles. This is a nonconforming condition with DCPP licensing basis
requirements. The licensee reported this unanalyzed condition to the NRC in Event
Notification Number 49879. Subsequent questions from the NRC resident inspector
prompted an evaluation of the DCPP licensing basis for tornado missiles. This
evaluation identified that the licensing basis requirements for EDG ventilation systems
and exhaust pipes require protection from tornado missiles.
The inspectors dispositioned the unanalyzed condition as a Green finding in
Section 1R15 of NRC Integrated Inspection Report 05000275/2014002 and
No additional deficiencies were identified during the review of this licensee event report.
This licensee event report is closed.
.2
(Closed) LER 05000275; 05000323/2012-005-01: Unanalyzed Condition due to
Nonconservative Change in Atmospheric Dispersion Factor
On July 5, 2012, as part of the LBVP, the licensee identified a non-conservative change
in the DCPP Final Safety Analysis Report Update (FSARU) Chapter 15, "Accident
Analyses," control room atmospheric dispersion factor (X/Q) methodology, made in
Revision 2 of the DCPP FSARU in 1986. The cause of this event was determined to be
an inadequate design control process in 1986, whereby the analysis change was made
without evaluating the change in accordance with 10 CFR 50.59 to determine whether or
not prior NRC review and approval was required. The corrective actions included:
(1) revising the X/Qs used in the analyses and incorporating them into the DCPP
licensing basis, and (2) submitting License Amendment Request 15-03 on
June 17, 2015, to request approval from the NRC to adopt the alternate source term as
allowed by 10 CFR 50.67.
The inspectors dispositioned the unanalyzed condition as a Green finding in
Section 1R15 of NRC Integrated Inspection Report 05000275/2012005
and 05000323/2012005.
No additional deficiencies were identified during the review of this licensee event report.
This licensee event report is closed.
.3
(Closed) LER 05000275/2013-008-00: Technical Specification 3.3.4 Not Met Due to
Inoperable Remote Shutdown System Function
a. Inspection Scope
The inspectors checked the accuracy and completeness of the LER and the
appropriateness of the licensees corrective actions. The licensee failed to properly
reinstall fuses that affected local manual operation of emergency diesel generator
(EDG) 1-3.
b. Findings
Introduction. The inspectors reviewed a self-revealing Green, non-cited violation of
Technical Specification 3.3.4 Remote Shutdown System, for the licensees failure to
- 29 -
maintain adequate configuration control of fuses associated with an EDG. The licensee
failure to maintain adequate configuration control by not verifying that fuses were
properly installed, and adequate post maintenance testing was performed, following
maintenance activities was a performance deficiency. Specifically, following the 1R17
refueling outage from approximately June 13, 2013 until November 22, 2013, EDG 1-3
would not have been able to perform its remote shutdown function due to not being able
to be adequately operated at the local EDG control cubicle.
Description. On November 19, 2013, DCPP maintenance technicians were conducting
relay testing on EDG 1-3 Output Breaker 52HF7, and discovered the breaker could not
be closed locally. Maintenance personnel found the US fuses in the 52HF7 cubicle in
the OFF position. With the US fuses in the OFF position, operators would not be able to
close EDG 1-3 output breaker at the breaker cubicle unless they opened the breaker
cubicle and manually closed the breaker. This manual operation was not
proceduralized, so successful performance of this task could not be guaranteed. Local
breaker closure capability is required to satisfy Technical Specification 3.3.4 remote
shutdown functionality in the event operation from the control room is not available.
Licensee personnel determined the US fuses in the 52HF7 cubicle were installed during
refueling outage maintenance activities in the incorrect position, and therefore failed to
maintain adequate configuration control of the EDG remote shutdown function as
required by technical specifications. Maintenance technicians restored the US fuses to
the correct position on November 22, 2013, and verified the positions of the US fuses in
the other EDG output breaker cubicles.
Licensee personnel determined that a human error by vendor maintenance technicians
was the most probable cause. A failure to maintain adequate configuration control of the
US fuses in the 52HF7 cubicle following the Unit 1 Refueling Outage 17 maintenance
activities most likely allowed the fuses to be reinstalled in the incorrect position.
Licensee personnel additionally determined that return to service testing following
maintenance activities was inadequate, in that it did not verify remote shutdown
functionality.
Analysis. The failure to properly install fuses in the local manual operation circuitry of
EDG 1-3 was a performance deficiency. The performance deficiency was more than
minor because it was associated with the protection against external events (fire)
attribute of the Mitigating Systems Cornerstone, and it adversely affected the
cornerstone objective of ensuring the availability, reliability, and capability of systems
that respond to initiating events to prevent undesirable consequences. Specifically, it
affected the ability to reach and maintain safe shutdown conditions in case of a fire
causing a control room abandonment. The inspectors evaluated this finding using
Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance
Determination Process," dated September 20, 2013. Because it affected the ability to
reach and maintain safe shutdown conditions in case of a fire that led to control room
evacuation, the Phase 2 methodology of Inspection Manual Chapter 0609, Appendix F,
was not appropriate for this finding. Therefore, the senior reactor analyst performed a
Phase 3 evaluation to determine the risk significance.
The analyst determined that the performance deficiency only increased the risk of the
plant as it related to the need to locally control EDG 1-3 following a postulated control
room evacuation. The analyst reviewed Abnormal Operating Procedure OP AP-8A,
Control Room Inaccessibility - Establishing Hot Standby, and determined that EDG 1-3
- 30 -
was only needed in the event of a control room evacuation that also included a loss of
offsite power. According to plant procedures, control room evacuations could be
initiated by fires in either the main control room or the cable spreading room.
The Senior Risk Analyst determined that the change in core damage frequency was less
than 1 x 10-6 and the finding was not significant with respect to large, early release
frequency. In accordance with the guidance in Inspection Manual Chapter 0609,
Appendix H, Containment Integrity Significance Determination Process, dated
May 6, 2004, the senior reactor analyst screened the performance deficiency for its
potential risk contribution to large early release frequency because the bounding change
in core damage frequency provided a risk significance estimate greater than 1 x 10-7 per
year. Given that DCPP has a large, dry containment and that control room evacuation
sequences do not include steam generator tube ruptures or intersystem loss of coolant
accidents, the analyst determined that this finding was not significant with respect to
large, early release frequency. Therefore, the analyst determined that this finding was of
very low risk significance (Green).
This finding had a cross-cutting aspect in the area of human performance associated
with the work practices component, because the licensee did not ensure supervisory and
management oversight of work activities, such that nuclear safety was supported [H.5].
Enforcement. Technical Specification 3.3.4 Remote Shutdown System, requires, in
part, that the EDG control function to be operable in modes 1, 2 and 3. Contrary to the
above, from June 13, 2013 until November 22, 2013, the licensee failed to ensure the
remote shutdown function was available. As a result, the availability of EDG 1-3 could
have been adversely impacted if the remote shutdown function was required. Because
the licensee entered the issue into its corrective action program as
Notification 50595473, and the finding is of very low safety significance (Green), this
violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the
NRC Enforcement Policy: NCV 05000275/2015002-04, Technical Specification 3.3.4
Not Met Due to Inoperable Remote Shutdown System Function.
This licensee event report is closed.
.4
(Closed) LER 05000275; 05000323/1-2014-004-00 and -01: Actuation of Six
Emergency Diesel Generators due to Loss of Offsite Power
a. Inspection Scope
On October 31, 2014, during a medium to heavy rain, the 230 kV offsite power source at
Diablo Canyon was lost due to an insulator flashover in the 230 kV switchyard resulting
in a valid actuation of all Unit 1 and 2 EDGs. As a result, the primary offsite power
source was lost, but the safety-related EDGs were available to provide vital buses if
there was a loss of main auxiliary buses.
b. Findings
(1) Introduction. The inspectors identified a Green, non-cited violation of
10 CFR 50.65(b)(2) for the licensees failure to appropriately scope the 230 kV
switchyard in the maintenance rule monitoring program. Specifically, from the inception
of the facilities monitoring program through May 18, 2015, the licensee failed to properly
- 31 -
scope or evaluate the 230 kV switchyard to include the entire switchyard up through the
first inter-tie circuit breakers CB262 and CB282 into the Maintenance Rule program.
Electrical faults within the 230 kV switchyard can cause loss of offsite power which is
relied upon to mitigate accidents and cause an actuation of a safety-related systems,
such as, EDGs, and should have been included into its Maintenance Rule program.
This issue was entered into the licensees corrective action program as Notifications
50702970 and 50703118.
Description. On April 28, 2015, during their review of the licensees root cause
investigation into the 230 kV flashover and loss of startup power documented in
Notification 50669932, the inspectors identified that this event had occurred while the
230 kV switchyard was in Maintenance Rule (a)(1) maintenance monitoring status. The
inspectors identified concerns related to the Maintenance Rule evaluation of the 230 kV
switchyard electrical distribution equipment. Following their evaluation, the inspectors
determined that the licensee had failed to appropriately scope the 230 kV offsite power
source to include the entire switchyard up through the first inter-tie circuit breakers
CB262 and CB282.
The inspectors determined the maintenance activities that occur in the switchyard can
directly affect plant operations and electrical components out to the first inter-tie circuit
breakers and therefore should have been considered for inclusion in the Maintenance
Rule. The following NRC requirements were reviewed by the inspectors:
Title 10 of the Code of Federal Regulations (10 CFR) 50.65(b) specifies:
(b) The scope of the monitoring program specified in paragraph (a)(1) of this section
shall include safety-related and non-safety-related structures, systems, and
components (SSCs), as follows:
(1) Safety-related SSCs that are relied upon to remain functional during and following
design basis events to ensure the integrity of the reactor coolant pressure boundary,
the capability to shut down the reactor and maintain it in a safe shutdown condition,
or the capability to prevent or mitigate consequences of accidents that could result in
potential offsite exposure comparable to the guidelines in Sec. 50.34(a)(1),
Sect. 50.67(b)(2), or sec. 100.11 of this chapter, as applicable.
(2) Non-safety-related structures, systems, or components:
(i) That are relied upon to mitigate accidents or transients or are used in plant
emergency operating procedures (EOPs); or
(ii) Whose failure could prevent safety-related structures, systems, and
components from fulfilling their safety-related function; or
(iii) Whose failure could cause a reactor scram or actuation of a safety-related
system.
The inspectors determined 10 CFR 50.65(b)(2) items (i) and (iii) are applicable for the
DCPP 230 kV offsite power source including the switchyard up through the first breakers
from the transmission system. Specifically, electrical faults within the 230 kV switchyard
can cause loss of offsite power which is relied upon to mitigate accidents and cause an
actuation of safety-related systems, such as EDGs. Inspectors discussed these results
- 32 -
with the Office of Nuclear Reactor Regulation (NRR), and NRR staff acknowledged the
issues and concurred on this inspection conclusion. In response to the inspectors
concerns, the licensee initiated Notification 50703118 to evaluate the need to include the
230 kV switchyard into its Maintenance Rule program. On May 18, 2015, following
discussions with inspectors, the licensee completed an evaluation of the maintenance
rule program and documented in Notification 50702970, the following conclusion:
A 230 kV switchyard bus fault of either Bus 1 or Bus 2 can cause a loss of the entire
230 kV switchyard as the bus fault will cause all switchyard breakers to open to clear
the bus fault. This type of event would cause a loss of function for which the 230 kV
system is scoped into the Maintenance Rule.
The licensee also concluded the Maintenance Rule scoping for the 230 kV offsite power
source failed to include the switchyard out to the offsite inter-tie breakers or up through
the first breakers from the transmission system.
Analysis. The inspectors determined that the licensees failure to scope the 230 kV
offsite power source including the switchyard up through the first breakers from the
transmission system into the Maintenance Rule program was contrary to the
requirements of 10 CFR 50.65 and therefore a performance deficiency. The
performance deficiency was determined to be more than minor because it is associated
with the initiating events attribute of protections against external factors and adversely
affected the cornerstone objective, in that, a 230 kV switchyard failure can upset plant
stability and challenge critical safety functions during shutdown as well as power
operations. Failure to monitor the performance or condition of 230 kV offsite power
source (including the switchyard up through the first breakers from the transmission
system) in a manner sufficient to provide reasonable assurance the offsite power was
capable of fulfilling the intended functions affected the reliability of the plant equipment to
perform their safety function.
The inspectors determined that had the 230 kV switchyard been properly scoped into the
Maintenance Rule program, the loss of offsite power due to the flash over event may
have been prevented. However the direct cause of the event was identified as untimely
corrective actions associated with an ineffective corrective action program. As such,
improper Maintenance Rule scoping was not the direct cause. Therefore, the inspectors
determined the finding could be evaluated using the significant determination process in
accordance using IMC 0609, Appendix A, Significance Determination Process (SDP) for
Findings At-Power, Exhibit 1, Initiating Events Screening Questions. The inspectors
determined that the finding was of very low safety significance (Green) because the
finding was determined not to be the cause of the actual 230 kV failure such that all of
the screening questions in Exhibit 1 could be answered no.
The inspectors determined that since the scoping of the switchyard systems had
occurred more than 3 years ago, and the opportunity to reevaluate system scoping had
not recently occurred, the finding did not represent current licensee performance and
therefore a cross-cutting aspect was not assigned.
Enforcement. Title 10 of the Code of Federal Regulations (10 CFR) 50.65(b)(2)
requires, in part, that the scope of the monitoring program specified in paragraph (a)(1)
of 10 CFR 50.65 shall include non-safety-related SSCs whose failure could prevent
safety-related SSCs from fulfilling their safety-related function. Contrary to the above,
from the inception of the facilities monitoring program through May 18, 2015, the
- 33 -
licensee failed to include a non-safety-related system and component whose failure
could prevent safety-related SSCs from fulfilling their safety-related functions in a
maintenance monitoring program. Specifically, the inspectors identified the 230 kV
offsite power source, including the switchyard up through the first inter-tie circuit
breakers, were not included in the maintenance monitoring program. Because this
violation was of very low safety significance and it was entered into the licensees
corrective action program as Notifications 50702970 and 50703118, this violation is
being treated as a non-cited violation, consistent with Section 2.3.2 of the NRC
Enforcement Policy: NCV 05000275/2015002-05; 05000323/2015002-05, Failure to
Appropriately Scope 230 kV Switchyard into the Maintenance Rule Monitoring Program.
(2) Introduction: The inspectors reviewed a self-revealing, Green finding for the licensees
failure to adequately implement procedure OM7.ID1, Problem Identification and
Resolution, to prevent a high voltage insulator flashover event in the 230 kV switchyard
that occurred on October 31, 2014. Specifically, corrective actions from three previous
root cause evaluations were not effective to prevent a loss of the 230 kV start-up power
and subsequent auto start of all of the safety standby EDGs.
Description: As documented in the licensees corrective action program trending
process, the licensee recognized increased susceptibilities to high-voltage insulator
flashovers were attributed to inadequate high voltage insulation design and preventative
maintenance strategies at Diablo Canyon. Over an extended period, the licensee
evaluated numerous high-voltage insulation failures, starting in August 2008, when
Unit 2 main bank transformer C-phase experienced a failure of the high voltage bushing.
The licensees corrective actions for the 2008 event included changes to bushing
materials to prevent reoccurrence. On October 11, 2012, the A-phase high voltage
insulator flashed over in light rain, which resulted in a Unit 2 reactor trip from full power.
Subsequent root cause evaluations recognized concerns with heavy contamination
deposition rates on high-voltage insulators. On June 23, 2013, during heavy fog,
multiple high voltage flashover events were experienced in the offsite switchyard in
Morro Bay, resulting in loss of 230 kV startup power to Diablo Canyon. Again, the
license recognized combined contamination levels and weather were factors in this
event. On July 10, 2013, hot washing of the Unit 2, high voltage insulators resulted in
overspray that caused the Unit 2 A-phase high-voltage insulator on the lightening
arrestor flashover. Because of these numerous high voltage insulator flashover events
the licensee conducted a common cause evaluation and implemented long term
corrective changes to high voltage insulators to increase design margin. On February 2,
2014, during light rain, another flashover of a Unit 2, B-phase high voltage insulator,
resulted in a Unit 2 reactor trip. As a result, interim corrective actions included
cleaning/washing lightning arrestors and high voltage insulators every three months.
Furthermore, on September 18, 2014, arcing in the 230 kV switchyard at Diablo Canyon
was observed. In that event, it was determined that cleaning of susceptible high-voltage
insulators in the switchyard was limited and was not completed on all of the 230 kV
switchyard high-voltage insulators.
However, an opportunity to clean the remaining high-voltage insulators was missed on
October 29, 2014. As a result three days later, on October 31, 2014, during heavy
rainfall, a high-voltage insulator flashover occurred in the Diablo Canyon 230 kV
switchyard resulting in a loss of startup power and subsequent start of all safety-related
EDGs.
- 34 -
Analysis: The licensees failure to adequately implement station procedure OM7.ID1,
Problem Identification and Resolution was a performance deficiency. The performance
deficiency was more than minor because it was associated with the human performance
attribute of the Initiating Events cornerstone and affected the cornerstone objective to
limit the likelihood of those events that upset plant stability and challenge critical safety
functions. Specifically, this failure resulted in another high-voltage insulator flashover,
which resulted in loss of 230 kV offsite startup power and activation of all safety-related
EDGs, on October 31, 2014.
Unit 1 Risk Impact
In accordance with IMC 0609.04, Initial Characterization of Findings, the inspectors
determined that the impact of the finding on Unit 1 should be evaluated using Exhibit 1 of
IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at
Power, because all questions in Table 3, SDP Appendix Router, were answered NO
directing the user to Appendix A. The inspectors determined that this finding required a
detailed risk evaluation by the regional senior risk analyst because the finding involved a
partial loss of 230 kV offsite power, a support system that contributes to the likelihood of
an initiating event (loss of offsite power) and affected mitigation equipment (EDGs).
The risk analyst determined that, with the 230 kV system deenergized, any plant
transient would result in a plant-centered loss of offsite power. Therefore, the
incremental conditional core damage probability (ICCDP) can be calculated as follows,
given the exposure period (EXP), the conditional core damage probability (CCDP) and
the total transient initiation frequency (Trans):
The analyst utilized the Standardized Plant Analysis Risk (SPAR) Model for Diablo
Canyon Units 1 & 2, Version 8.23 to calculate the total Trans of 1.1775/year. Additionally,
the analyst quantified the SPAR for a plant-centered loss of offsite power to obtain the
CCDP of 1.73 x 10-4. Given that the 230 kV support system was unavailable from 17:40
on October 31, 2014 until 02:29 on November 1, 2014, the total exposure period was
approximately 9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br />. The analyst then calculated the ICCDP as follows:
ICCDP = 1.18/year * 1.73 x 10-4 * 9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> ÷ 8760 hour0.101 days <br />2.433 hours <br />0.0145 weeks <br />0.00333 months <br />s/year
= 2.09 x 10-7
Given that the incremental conditional core damage probability is less than the 1 x 10-6
threshold in the significance determination process, this finding is of very low safety
significance (Green) for Unit 1.
Unit 2 Risk Impact
In accordance with IMC 0609.04, Initial Characterization of Findings, the inspectors
determined that the impact of the finding on Unit 2 should be evaluated using IMC 0609,
Appendix G, Shutdown Operations Significance Determination Process, because the
finding pertained to operations, an event, or a degraded condition while the plant was
shut down. Unit 2 was shutdown in a refueling outage when the event occurred on
October 31, 2014. Appendix G is used to evaluate findings that: (1) increase the
likelihood or cause an event, or (2) affect the ability to mitigate an event. Because of the
- 35 -
shutdown configuration of Unit 2, the loss of the 230 kV support system did not impact
the ability to continue to provide decay heat removal for the unit. The only direct effect
on the unit was the anticipatory start of the three Unit 2 diesel generators. Therefore,
the analyst determined qualitatively that this finding is also of very low safety significance
(Green) for Unit 2.
This finding has a cross-cutting aspect of work management, in the area of human
performance, for failing to implement a process of planning, controlling, and executing
work activities such that nuclear safety is an overriding priority. Specifically the licensee
failed to effectively plan and coordinate preventative maintenance strategies associated
with root causes from previous high-voltage insulators flashover or failures since 2008 to
prevent the loss of offsite 230 kV and the transient on October 31, 2014 [H.5].
Enforcement: This finding does not involve enforcement action because no violation of a
regulatory requirement was identified. The licensee took corrective actions to update
interface requirements for transmission and distribution facilities at Diablo Canyon, and
implement a comprehensive time based preventative maintenance washing program.
The licensee entered this finding into their corrective action program as
Notification 50699230. Because this finding does not involve a violation of regulatory
requirements and is of very low safety or security significance, it is identified as a
FIN 05000275/2015002-06; 05000323/2015002-06, High Voltage Insulator Flashover
Resulted in Loss of 230 kV Offsite Power and Start of Emergency Diesel Generators.
.5
(Closed) Unresolved Item 05000275/2014004-05 Notice of Enforcement
Discretion 14-4-001 for a Loss of Both Required Offsite Power Circuits
a.
Inspection Scope
As discussed in detail in Inspection Report 05000275; 05000323/2014004, Section
4OA3.4, the NRC telephonically granted at 3:07 p.m. on August 15, 2014, Notice of
Enforcement Discretion (NOED) 14-4-001 for Pacific Gas & Electric, to allow an
additional 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> to restore compliance with Technical Specification 3.8.1, AC Sources
- Operating, Condition H. However, one of the two inoperable EDGs was restored to
operable status at 6:31 p.m. on August 15, 2014, which was within the original technical
specification required action completion time. Therefore, the additional time granted by
the NOED was no longer necessary. Nonetheless, the inspectors performed a review of
the circumstances associated with the granting of NOED 14-4-001, verified the
licensees oral assertions, including the likely cause and compensatory measures, and
verified the notice of enforcement discretion request was consistent with the staffs policy
and guidance.
b.
Findings
No findings were identified.
These activities constitute completion of five event follow-up samples, as defined in Inspection
Procedure 71153.
- 36 -
4OA6 Meetings, Including Exit
Exit Meeting Summary
The inspectors debriefed Ms. Gerfen, Director, Operations Services; Mr. Petersen, Director,
Learning Services; and other members of the licensee's staff of the results of the licensed
operator requalification program inspection on May 21, 2015, and telephonically exited with
Mr. Welsch, Site Vice President, and other staff members on June 16, 2015. The licensee
representatives acknowledged the findings presented. The inspectors asked the licensee
whether any materials examined during the inspection should be considered proprietary. No
proprietary information was identified.
On July 7, and July 28, 2015, the resident inspectors presented the inspection results to Mr.
J. Welsch, Site Vice President, and other members of the licensee staff. The licensee
acknowledged the issues presented. The licensee confirmed that any proprietary information
reviewed by the inspectors had been returned or destroyed.
4OA7 Licensee-Identified Violations
The following Severity Level IV violations were identified by the licensee and are violations of
NRC requirements which meet the criteria of the NRC Enforcement Policy for being
dispositioned as non-cited violations.
.1
Title 10 of the Code of Federal Regulations (10 CFR) 50.9, Completeness and accuracy
of information, Section (a) states, in part, that information required by statute or by the
Commission's regulations, orders, or license conditions to be maintained by the
applicant or the licensee shall be complete and accurate in all material respects.
License Condition 2.C.(5) for Unit 1 and 2.C.(4) for Unit 2, Fire Protection, require, in
part, that the licensee shall implement and maintain in effect all provisions of the
approved fire protection program as discussed in its Final Safety Analysis Report
Update. Final Safety Analysis Report Update Appendix 9.5H, Inspection and Testing
Requirements and Program Administration, addresses control of combustible materials
in Special Consideration E, Combustible Materials in Safety-Related Areas. Special
Consideration E states, in part, Use of combustibles in safety-related areas is to be
strictly controlled and is the responsibility of the area or work supervisor. Specific
controls are delineated in plant procedures. Procedure OM8.ID4, Control of
Flammable and Combustible Materials, provides the specific administrative controls
required to keep bulk transient combustible materials within the plant Fire Hazards
Analysis design basis. Step 5.6.4(i) of Procedure OM8.ID4 requires transient
combustible permits to be walked down by the job supervisor or designee once the
permit is in place and every week thereafter until the transient control permit is removed.
Walk downs are documented and any deficiencies noted on DCPP Form 69-13206,
Procedure OM8.ID4, Attachment 3, Transient Combustible Inspection.
Contrary to the above, on April 8, 2014, June 18, 2014, and July 16, 2014, the licensee
failed to complete the walkdowns for the transient combustible permits required by
procedure though they were documented as completed. Specifically, an employee of
the licensee deliberately documented the completion of the transient combustible permit
inspections (walkdowns) within the radiological control area per Procedure OM8.ID4,
when, in fact, he had not completed the inspections. This caused the licensee to be in
violation of License Conditions 2.C.(5) and 2.C.(4) of licenses DPR-80 and DPR-82,
- 37 -
respectively. This is material to the NRC because the review of transient combustible
permit inspections, and associated records, are reviewed as part of the NRCs
inspection of the licensees fire protection program. The licensee identified the violation,
entered the issue into the corrective action program as Notification 50710885, and took
appropriate corrective actions. These included completing confirmatory walkdowns on
July 16, 2014, of the transient combustible permits in question, and performing an
internal corporate investigation as to the cause. Using Inspection Manual Chapter 0609,
Appendix F, Fire Protection Significance Determination Process, the violation was
determined to be of very low safety significance because the reactors were able to reach
and maintain a safe shutdown condition. Traditional enforcement applied to this finding
because it involved a violation that impacted the regulatory process. Assessing the
violation in accordance with Enforcement Policy, the violation was determined it to be of
Severity Level IV (SL-IV) because it resulted in a condition evaluated by the Significance
Determination Process as having very low safety significance (Enforcement Policy
example 6.1.d.2).
In accordance with Section 2.3.2.a of the Enforcement Policy, and with the approval of
the Director, Office of Enforcement, this issue has been characterized as a non-cited
violation, because (1) the licensee entered the issue into its corrective action program;
(2) the licensee promptly restored compliance after identification of the issue; and (3) the
violation was not repetitive as a result of inadequate corrective action. Additionally,
though the violation was willful, (1) the violation was identified by the licensee; (2) the
violation involved the act of an individual, who would not have been considered a
licensee official with oversight of regulated activities as defined in the Enforcement
Policy; (3) the violation did not involve a lack of management oversight and was the
isolated action of the former employee; and (4) significant remedial action
commensurate with the circumstances was taken by the licensee. (EA-15-040)
.2
Title 10 of the Code of Federal Regulations (10 CFR) 50.74(c) requires, in part, that
licensees shall notify the appropriate Regional Administrator within 30 days of a
permanent disability of a licensed operator as described in 10 CFR 55.25. Contrary to
the above, from 2009 to March 4, 2013, the licensee failed to notify the appropriate
Regional Administrator when a licensed operator was diagnosed with a permanent
disability. The licensee documented this issue in DA 50540600. This violation was
determined to impact the regulatory process and was evaluated using Section 2.2.2 of
the NRC Enforcement Policy. In accordance with Section 6.4.d of the NRC Enforcement
Policy, this violation was determined to be a Severity Level IV violation because of the
failure to report a medical condition that would have required a license restriction to
maintain medical qualifications.
A-1
Attachment
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
B. Allen, Vice President Nuclear Services
T. Baldwin, Director, Nuclear Site Services
J. Becerra, Supervisor, Exam/Simulator
D. Evans, Director, Security & Emergency Services
R. Fortier, Exam Developer
P. Gerfen, Director of Operation Services
M. Ginn, Manager, Nuclear Emergency Planning
E. Halpin, Sr. Vice President, Chief Nuclear Officer
A. Heffner, NRC Interface, Regulatory Services
J. Hinds, Director, Quality Verification
H. Hamzehee, Manager, Regulatory Services
T. Irving, Manager, Radiation Protection
J. Lyle, Supervisor, Operations Continuing Training
J. MacIntyre, Director of Equipment Reliability
M. McCoy, Regulatory Services, NRC Interface
J. Morris, Senior Advising Engineer
J. Nimick, Station Director
A. Peck, Director, Nuclear Engineering
L. Sewell, Nuclear Radiation Protection Engineer
R. Simmons, Manager, Nuclear Maintenance
A. Warwick, Supervisor, Emergency Planning
J. Welsch, Site Vice President
E. Werner, Manager, Operations Training
M. Wright, Nuclear Engineering, Manager
NRC Personnel
D. Loveless, Senior Reactor Analyst
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened and Closed 05000275/2015002-01
Failure to Appropriately Pre-plan and Perform Maintenance on
Hydrogen Guard Piping (Section 1R05)05000275/2015002-02
Failure to Maintain Operator Licensing Examination Integrity
(Section 1R11)05000275/2015002-03
Inadequate Design Control for High-Energy Line Break Vent
Flow Path (Section 4OA2.4)05000275/2015002-04
Technical Specification 3.3.4 Not Met Due to Inoperable Remote
Shutdown System Function (Section 4OA3.3)05000275/2015002-05
Failure to Appropriately Scope 230 KV Switchyard into the
Maintenance Rule Monitoring Program (Section 4OA3.4.b.(1))
A-2
Opened and Closed 05000275/2015002-06
High Voltage Insulator Flashover Resulted in Loss of 230 kV
Offsite Power and Start of Emergency Diesel Generators
(Section 4OA3.4.b.(2))
Closed
05000275/2014-003-02
05000323/2014-003-02
LER
Unanalyzed Condition Affecting Unit 1 and 2 Emergency
Diesel Generators, Tornado Missiles (Section 4OA3.1)
05000275/2012-005-01
05000323/2012-005-01
LER
Unanalyzed Condition due to Nonconservative Change in
Atmospheric Dispersion Factor (Section 4OA3.2)
05000275/2013-008-00
LER
Technical Specification 3.3.4 Not Met Due to Inoperable
Remote Shutdown System Function (Section 4OA3.3)
05000275/2014-004-00
05000323/2014-004-00
LER
Actuation of Six Emergency Diesel Generators due to Loss of
Offsite Power (Section 4OA3.4)
05000275/2014-004-01
05000323/2014-004-01
LER
Actuation of Six Emergency Diesel Generators due to Loss of
Offsite Power (Section 4OA3.4)0500275/2014004-05
Notice of Enforcement Discretion 14-4-001 for a Loss of Both
Required Offsite Power Circuits (Section 4OA3.5)
Section 1R01: Adverse Weather Protection
Procedure
Number
Title
Revision
CP M-16
Severe Weather
4
Notifications
50696079
50696186
Section 1R04: Equipment Alignment
Procedure
Number
Title
Revision
OP1.DC20
Sealed Components
20
OP J-6B:XI
Diesel Generator 2-2 Startup
1
Notifications
50441192
50441193
50702486
A-3
Drawing
Number
Title
Revision
106703
OVID Unit 2 Auxiliary Feedwater System
50
Section 1R05: Fire Protection
Notifications
50673544
50317795
50695031
50702504
50778755
50697654
50685679
50698510
50697655
50684755
50697653
50698135
50622152
Drawings
Number
Title
Revision /
Date
RA-5
Pre-Fire Plans 85 foot Auxiliary Building
10
111906-17
Fire Protection 85 foot Auxiliary Building
10
515221-2
Door Schedule- Unit 1
February 20, 2015
515224-2
Door Schedule- Unit 2
March, 26, 2014
TB-14/16
Unit 2, Fire Plan- Turbine Building Elev. 85 foot
6
111906
Unit 2, Fire Protection Turbine Building Elev. 85 foot
6
108008
Chemical & Volume Control System
106
108026
Nitrogen and Hydrogen Systems-Unit 1
25
Procedures
Number
Title
Revision
CF3.ID11
Seismic Configuration Control Program
9
AD7.DC8
Work Planning
45A
AD7.DC6
On-Line Maintenance Risk Management
21B
OM8
4
OM8.ID1
Fire Loss Prevention
25
OM8.ID2
Fire System Impairment
18
OM8.ID4
Control of Flammable and Combustible Materials
22A
TP TO-15001
VCT H2 Regulator PCV-955 Repair or Replacement
0
A-4
Miscellaneous Document
Number
Title
Date
C19 D-08-027
Clearance H2 Supply Regulator to VCT 1-1
January 28, 2015
Section 1R06: Flood Protection Measures
Notifications
50509840
50508365
Drawings
Number
Title
Revision
515220-2
Unit 1 Door Schedule Operational Requirements
26
515220-1
Unit 1 Door Schedule
61
Section 1R11: Licensed Operator Requalification Program and Licensed Operator
Performance
Procedures
Number
Title
Revision
R137-EI-1
Instructors lesson Scenario Guide
20
TQ2.DC3
Licensed Operator and Shift Technical Advisors
Continuing Training Program
25
TQ2.DC15
Licensed Operator Annual/Biennial Exam
Development and Administration Guidelines
3
TQ2.ID4
Lesson Scenario Plan
0
TQ2.DC15
Licensed Operator Annual/Biennial Exam
Development and Administration
5
TQ2.DC3
Licensed Operator Continuing Training Program
26
TQ1.DC.28
Simulator Testing
1
SQA 99-2
Operator Training Simulator Software Quality
Assurance
2
CF2.DC1
Configuration Management Plan for the Operator
Training Simulator
9
CF4.ID3
Modification Implementation
29
STA-213
Use of RETRAN to Assess DCPP Plant Simulator
Operability Testing Performance
0
TQ2.ID4
Training Program Implementation
38
A-5
Procedures
Number
Title
Revision
OP1.ID2
Time Critical Operator Actions
8A
OP1.DC10
Conduct of Operations
43
OM14.ID2
Medical Examinations
9
TQ2.DC13
Shift Technical Advisor/Incident Assessor Training
Program
2
Miscellaneous Documents
Number
Title
Revision /
Date
NRC Pre-Inspection Self-Assessment Report
March 10, 2015
Shift Manager / STA / IA Self-Assessment Report
December 25, 2014
Simulator Review Team Quarterly Meeting Minutes
January 9, 2014
Simulator Review Team Quarterly Meeting Minutes
June 12, 2014
Simulator Review Team Meeting Minutes
January 22, 2015
Simulator Review Team Quarterly Meeting Minutes
September 26, 2013
Simulator Review Team Quarterly Meeting Minutes
June 27, 2013
Simulator Review Team Quarterly Meeting Minutes
March 27, 2013
Simulator Review Team Meeting Minutes
March 31, 2015
LOCT CRC Ad Hoc Meeting Minutes
April 9, 2015
LOCT Curriculum Review Committee Meeting
Minutes
January 9, 2014
LOCT Curriculum Review Committee Meeting
Minutes
November 19, 2014
LOCT Curriculum Review Committee Meeting
Minutes
January 28, 2015
B.3.2.1(2)
Transient Test Trip of All Feedwater Pumps
September 6, 2014
B3.2.1(7)
Transient Test Maximum Rate Power Ramp
September 6, 2014
B3.2.1(10)
Transient Test Stuck PORV without High Head
September 13, 2014
Simulator/Plant Differences of Note
SCR 2013-055
Model New Alarm Input 1625 on PK2020
January 24, 2015
SCR 2012-050
1R18 Mod for U1 MBT Oil Pump Replacement
January 24, 2015
A-6
Miscellaneous Documents
Number
Title
Revision /
Date
1000024867
Design Change Package Summary
0
February 23, 2015
SBT Loss of Reactor Pressure Control
February 23, 2015
SBT NI-44 Failure
February 23, 2015
2013-2014 LOCT POI
2
SCR 2012-013
Evaluate if Emergency Borate Flow is Correct
SCR 2014-058
RHR Discharge Pressure Increases to Relief
Setpoint on Safety Injection Where RCS Pressure
is Above Shutoff Head
SCR 2013-027
Correct Rod Lo/Lo-Lo Alarms on S/U
SCR 2012-025
Update CST Lo Level Alarm LS478 Setpoint
DDP
1000000469
Design Change Package Summary
0
Simulator Determination of Moderator Temperature
Coefficient at HZP, BOL
March 13, 2014
Simulator Rod Worth Measurements Using Rod
Swap Method
March 13, 2014
Control Room Log Entries 2/8/14 & 10/5/14
Crew D training records
Licensed Operator Reactivation Records
Annual Operating Tests
Biennial Written Examination
R147
Remediation Package for RO 2015 Biennial Exam
April 22, 2015
R137
Remediation Package for 2014 Annual Exam
May 23, 2014
40% plant comp 2014.xls (40 percent steady state
simulator test data)
18% plant comp 2014.xls (18 percent steady state
simulator test data)
A-7
Notifications
50549004
50556077
50592099
50627628
50688192
50694912
50698753
50703049
50703106
50703139
50703258
50703259
50703308
50703369
50703411
50703413
50703414
50703422
50703423
50703448
50703449
50703485
50703496
50703550
50703551
50703556
50703557
50657245
Section 1R12: Maintenance Effectiveness
Notifications
50698248
50698528
50673779
50673158
5067566
50683171
Section 1R13: Maintenance Risk Assessments and Emergent Work Control
Procedures
Number
Title
Revision /
Date
OP J-2:VII
Offsite Power Sources - de-energizing
10
PGE DW-15-0192 Switching Log and Clearance Setup
April 9, 2015
AD7.DC6
On-Line Maintenance Risk Management
21B
AD7.ID14
Assessment of Integrated Risk
1
OP J-2:VIII
Guideline for Reliable Transmission Service for DCPP
26
AD7.ID14
Assessment of Integrated Risk
5
Notifications
50231071
50425987
50704663
50708371
50708054
50673779
50673158
5067566
A-8
Drawings
Number
Title
Revision /
Date
LCOTR 0-TS-15-
0056
Tracking Technical Specification Report
April 22, 2015
0-C19 D-18-047
Carbon Dioxide Hose Reel Clearance Scope
April, 22, 2015
Calculation File
No. C13
PRA Evaluation of Various Maintenance Configurations to
Support On-Line Risk Assessment
4
Section 1R15: Operability Determinations and Functionality Assessments
Procedure
Number
Title
Revision
OM10.DC3
Emergency Response Facilities, Equipment, and
Resources
7
Notifications
50695180
50695372
50687000
50687004
50698075
50703770
50673779
50673158
5067566
505697487
Section 1R18: Plant Modifications
Procedures
Number
Title
Revision
TP TO-13007
Traveling Screen 2-7 Replacement Contingencies
1
CF4
Modification Control
7
Notifications
60017014
50250296
Section 1R19: Post-Maintenance Testing
Procedures
Number
Title
Revision
STP-P-DFO-02
Routine Surveillance Test of Diesel Fuel Oil Transfer Pump
0-1
9
AD13.ID4
Post Maintenance Testing
22B
A-9
Procedures
Number
Title
Revision
STP-M-51
Routine Surveillance Test of Containment Fan Cooler Units 36
MP E-50.30B
Agastat Type ETR Timing Relay Maintenance
25
Notifications
50700093
50606336
50701876
50701916
50699768
50704308
50703393
50704452
Work Orders
64068095
64113509
60079526
Section 1R22: Surveillance Testing
Procedures
Number
Title
Revision
STP P-ASW-A11 Comprehensive Test of Auxiliary Saltwater Pump 1-1
8
STP I-38-B.1
SSPS Train B Actuation Logic Test in Modes 1,2,3, or 4
25
STP I-38-B.2
SSPS Train B SI Reset Timer and Slave Relay K602 Test
10
STP M-9G
Diesel Generator 24-Hour Load Test and Hot Restart Test
54
Notifications
50703698
50705639
Work Orders
64079112
64077108
64077118
Section 1EP6: Drill Evaluation
Procedures
Number
Title
Revision
EN-1 PEP
Plant Accident Mitigation Diagnostic Aids and Guidelines
25
OP H-5:1
Control Room Ventilation - Prepare for Service
R17
A-10
Notifications
50683410
50706695
50706696
50706697
Section 4OA2: Problem Identification and Resolution
Procedure
Number
Title
Revision
STP M-70.SWG
Swing Door Surveillance Test
1
Notifications
50698455
50698102
50710846
50659268
50496405
Other Documents
Number
Title
Revision
M-493
Calculation Area H&K Auxiliary Building Pressure and
Temperatures due to Pipe Breaks
2
DCM T-12
Pipe Break (HELB/MELB), Flooding and Missiles Design
Change DCP M-49919
14C
Section 4OA3: Follow-up of Events and Notices of Enforcement Discretion
Procedures
Number
Title
Revision
SDP-13-07
High Wind Effect on Unit 1 EDG Ventilation System
0
SDP-13-06
Loss of Local Control of EDG 1-3 Output Breaker
0
Notifications
50599190
50595473
50484887
50702970
50703118
50596870
50669226
50700062
50682553
50603815
50683219
50688823
50231071
50707353
50669932
50573100
50702094
50699875
50627559
50586410
Procedures
Number
Title
Revision
OP AP-8A
Control Room Inaccessibility - Hot Standby
38
A-11
Procedures
Number
Title
Revision
OP AP-8B
Control Room Inaccessibility - Coly Shutdown
26TP
DCPP Scoping
System 69: 230 kV System
2
OM1.ID4
Interface Requirements for Transmission & Distribution
Facilities at DCPP
6A
AWP E-016
Inspection Guide - Maintenance Rule & License Renewal
Structural Monitoring Programs - Civil
6
MA1.NE1
Maintenance Rule Monitoring Program -Civil
Implementation
5
MA1.ID17
Maintenance Rule Monitoring Program
28
OP J-2:VII
Offsite Power Sources - Deenergizing SUT 1-1 & 2-1 for
230 kV Maintenance
10
OM7.ID1
Problem Identification and Resolution
46